Method and apparatus for using pressure cycling and cold liquid CO2 for releasing natural gas from coal and shale formations

ABSTRACT

A method and apparatus for sequestering carbon dioxide (CO 2 ) gas and releasing natural gas from underground coal and/or gas shale formations using CO 2  gas captured from the flue gas of a coal burning power plant, and processing it to produce cold liquid pressurized CO 2 , and injecting the cold liquid CO 2  under pressure to create fractures within the formation and causing the CO 2  to be adsorbed into the coal or gas shale and natural gas (CH 4 ) to be desorbed, released and recovered. A special pressure cycling process is used to enable the pressure within the formation to be increased and decreased, including allowing the liquid CO 2  to change phase to a gaseous CO 2 , and injecting the liquid CO 2  under pressure repeatedly, which causes greater expansion of the proliferation zone within the formation, and more efficiently releases CH 4 .

RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application Ser.No. 61/553,166, filed Oct. 29, 2011. This application is a continuationin part of and incorporates by reference U.S. application Ser. No.12/930,117, filed Dec. 28, 2010, which claims the benefit of U.S.Provisional Application Ser. No. 61/284,960, filed Dec. 28, 2009.

FIELD OF THE INVENTION

The invention relates to a method and apparatus for using pressurecycling and liquid CO₂ (also referred to as LCO₂) to release methanefrom coal and shale formations, and in particular, to using cold liquidCO₂ and injecting it under pressure above the fracture gradient tocreate fractures within the formation and then to reduce the pressure toallow cleats to form within the formation and then to repeat the cycleusing cold liquid CO₂ again, to cause CO₂ to be adsorbed and CH₄ to bedesorbed, wherein methane can be released and recovered from theformation.

BACKGROUND OF THE INVENTION

Hydraulic fracturing is a process that creates fractures in rockformations (or reservoirs), which has the effect of increasing theoutput of a well. The most important industrial use of this process isfor stimulating oil and gas wells. Natural fracturing includes volcanicdikes and sills and frost weathering. Man-made fractures are commonlyextended into targeted rock formations and are typically created usingwellbores drilled into the formations to enhance oil and natural gasrecovery, such as from coal beds and shale rock, etc.

Hydraulic fractures are typically extended by creating internal fluidpressure into the formations which opens the fractures and causes themto extend through the formations. The fracture width is typicallymaintained by introducing a proppant, such as sand, ceramic, or otherparticulates, wherein the imposition of the proppant into the openingshelps to prevent the fractures from closing when the injection isstopped.

Hydraulic fracturing helps remove natural gas and oil from rockformations deep within the earth's crust where there are insufficientporosity and permeability levels to allow these resources to flow fromthe reservoir to the wellbore at economic rates. In such case, thefractures preferably provide a conduit or path that connects thereservoir to the well, thereby increasing the area from which naturalgas and liquids can be recovered.

The process used includes pumping the fracturing fluid into the wellboreat a rate sufficient to increase its pressure to above the fracturestrength of the rock formation. This pressure causes the rock formationto crack, allowing the fracturing fluid to enter and extend through theformations. To keep this fracture open after the injection stops, aproppant, such as sand, is often added to the fracture fluid. Thepropped hydraulic fracture then becomes a permeable conduit throughwhich the fluid can flow.

Because drilling a borehole typically involves using a rotating drillbit, chips and particles of rock are often produced that can adverselyaffect the passage of fluid through the wellbore, resulting in reducedpermeability and flow of fluid into the borehole. The borehole can alsobe sealed by the surrounding rock, wherein hydraulic fracturing can beused to increase the flow of fluid through the rock.

Various types of proppant, including sand, resin-coated sand, andman-made ceramics are typically used depending on the desiredpermeability or grain strength. The injected fluid mixture is typicallyabout 99% water and sand, although the fracture fluid can also be gel,foam, nitrogen, or even air, etc.

In addition to the fluid, certain chemicals are often added to enhancethe effectiveness of the fracturing i.e., the flow of natural gas to thesurface. Thus, considerable environmental concerns have arisen,including the possibility that chemicals and other waste fluids mightbleed into water aquifers, as well as the possible erosion anddeformation that can result once fractures have been created andresources have been removed.

Environmental and health concerns associated with hydraulic fracturinginclude contamination of ground water, risks to air quality, themigration of gases and chemicals to the surface, the creation of seismicevents, and the potential mishandling of waste. The potential costsassociated with environmental clean-up, loss of land value, and humanand animal health concerns are still being investigated and evaluated.

Hydraulic fracturing has favorably increased the production of naturalgas from coal beds and shale rock formations in recent years. In thepast, methane gas has been released during mining and post-miningactivities, including various methane emissions which can be dividedinto the following categories:

Underground Mining: Methane gas can be removed from underground minesbefore and during mining by using degasification systems. The gas can bevented, flared (not currently done in the U.S.), or recovered for itsenergy content. Indeed, up to 50 to 60 percent of methane can typicallybe recovered from mines using degasification, wherein the remainder isreleased into the atmosphere. In underground mining, methane gas isoften released into the mine shafts wherein methane is diluted into theventilation air and then vented to the atmosphere.

Surface Mining: During surface mining, methane is typically releasedinto the atmosphere as the overlying rock strata are removed, althoughfor this type of release, no emissions mitigation options are currentlybeing used. In theory, some pre-mining degasification and recovery couldoccur in certain surface mines. However, the low gas content of mostsurface mines relative to that of underground mines makes it unlikelythat significant recovery would be technically feasible, let alonecost-effective.

Abandoned Mines: There are several thousand abandoned coal mines in theUnited States today. Of these, the EPA has identified some 400 that areconsidered “gassy.” Even though active mining no longer occurs, thesemines can still produce significant methane emissions from diffusevents, fissures, or boreholes, etc., which can be extracted and used togenerate power, etc., although these emissions are not quantified orincluded in U.S. inventory estimates.

Coal mines already employ a range of technologies for recovering methanegas. These methods have been developed primarily for safety reasons, asa supplement to ventilation systems, to circulate dangerous methane gasfrom the mines. The major degasification technologies currently used inthe U.S. include vertical wells, long-hole and short-hole horizontalboreholes, and gob wells which are excavated mine areas that have beenallowed to collapse. The quality of the gas extracted by these methodsdetermines how they may be used. Vertical wells and in-mine horizontalboreholes produce nearly pure methane, while gob wells, which recoverpost-mining methane, typically recover methane mixed with air.

Even when degasification systems are used, mines still emit significantquantities of methane via ventilation systems. Technologies are indevelopment that would catalytically oxidize the low concentrations ofmethane in ventilation air, producing usable thermal heat as aby-product. Methane recovered by degasification can be used for pipelineinjection, power generation, on-site use in thermal coal dryingfacilities, or sold to nearby commercial or industrial facilities, etc.At present, most recovered coal mine methane is sold through natural gaspipelines.

Mines that are already recovering methane represent opportunities forutilities to work with mine operators to develop a use strategy.Utilities may also be able to participate in projects that are notcurrently recovering methane by implementing projects that include bothgas recovery and utilization.

Coal bed gas formations or reservoirs often contain an orthogonalfracture set called cleats that are often oriented perpendicular to thebedding (which is nearly horizontal), which provide the primary conduitfor upward fluid flow. Gas typically diffuses from the matrix into thesecleats and flows up to the well bore. In coal bed gas reservoirs, thekey parameters for controlling the amount of gas in place include coalbed thickness, coal composition, gas content, and gas composition. Coalcomposition refers to the amount and type of organic constituents foundin the coal, which has a significant effect on the amount of gas thatcan be adsorbed and/or desorbed. Gas contents in coal seams vary widely(<1 to >25 sm³/tonne) and are a function of coal composition, thermalmaturity, burial and uplift history, and the addition of migratedthermal or biogenic gas. Note that 1 ton is 2,000 pounds and 1 tonne is2,406.2 pounds. Gas composition is generally greater than 90% methane,with minor amounts of liquid hydrocarbons, carbon dioxide, and/ornitrogen.

Gas productivity from coal bed reservoirs is controlled primarily by thecoal's permeability and the gas-saturation state. Permeability inproducing areas typically ranges from a few millidarcies to a few tensof millidarcies, although permeabilities exceeding 1 Darcy have beenreported. Absolute permeability increases with time as gas desorbs fromthe coal, causing the matrix to shrink and the cleats to widen, althoughthis may be offset by a reduction in cleat aperture because of increasednet stress caused by reservoir-pressure depletion.

Permeability is a key factor for coal bed methane (CBM) recovery. Coalbeds are typically low in permeability, and almost all the permeabilityis usually due to fractures, which in coal beds are typically in theform of cleats and joints. Coal cleats are of two types: butt cleats andface cleats, which occur at nearly right angles. The face cleats arenormally continuous and provide paths of higher permeability while buttcleats are usually non-continuous and end at face cleats.

Gas contained in coal beds are mainly methane and trace quantities ofethane, nitrogen, carbon dioxide and some other gases. Intrinsicproperties of coal found in nature determine the amount of gas that canbe recovered. The porosity of coal bed reservoirs is usually very small,ranging from 0.1 to 10%. The adsorption capacity of coal is defined asthe volume of gas adsorbed per unit mass of coal usually expressed inSCF (standard cubic feet, the volume at standard pressure andtemperature conditions) gas/ton of coal. The capacity to adsorb dependson the rank and quality of the coal. The adsorption ranges from 100 to800 SCF/ton for most coal seams found in the United States. Most of thegas in coal beds is in the adsorbed form.

The permeability that is produced from fractures acts as the majorchannel for gas to flow—the higher the permeability the higher the gasproduction. For most coal bed seams found in the United States, thepermeability lies in the range of 0.1 to 50 millidarcies. Thepermeability changes with the stress applied to the formation. Coaldisplays a stress-sensitive permeability and this process plays animportant role during stimulation and production operations.

Hydraulic fracturing can be used to enhance gas recovery from coal bedsby increasing their permeability. Since methane is stored (adsorbed)over time on the micropores of the coal itself, and this storagecapacity is a function of the amount of pressure that has been exertedon the coal surfaces, i.e., the higher the pressure the greater thestorage potential, production or release of gas from the coal normallyrequires the reduction of pressure within the formation. This pressurereduction frees the methane molecules from the coal bed and allowsupward gas migration.

Water/gas separators used for conventional gas production are oftenmodified to accommodate copious amounts of “produced” water andassociated coal fines (small particles of coal that can pollute thewater). After hydrostatic pressure is reduced, methane gas is desorbedfrom the coal and is then free to migrate through the permeable strataand fractures to an area of lower pressure, i.e., ideally into wellbores that created the pressure reduction. Since water must be withdrawnto reduce the pressure and allow gas migration, the volume of gasproduced tends to build from a low initial rate to a maximum rateseveral years after the onset of production. When reservoir pressuredrops below 150 psi, the well is no longer considered economic. It isestimated that less than 50% of the coal bed methane in place can beeconomically recovered by reservoir pressure depletion strategy. Thus,in areas like the San Juan Basin, enhanced production techniques havebeen used.

Another enhancement technique available introduces nitrogen under highpressure through injector wells into individual coal beds. Nitrogensorption displaces the methane on the coal molecules and reduces thepartial pressure of the methane. Beginning in the 1980's, some companieshave experimented with this technique and found that up to 80% of themethane can be recovered with this strategy.

Gas bearing shale and tight sands are also making an emergence due tothe application of newer technologies such as horizontal drilling andadvanced stimulation methods including hydraulic fracturing. In thisapplication we are not considering oil shale; we are considering gasshale. Oil shale is a term used to cover a wide range of fine-grained,organic-rich sedimentary rocks. Oil shale does not contain liquidhydrocarbons or petroleum as such but organic matter derived mainly fromaquatic organisms. This organic matter, kerogen, may be converted to oilthrough destructive distillation or exposure to heat. The recoveredorganic fraction is then distilled, or pyrolyzed to produce thefollowing products: crude shale oil, flammable hydrogen gas, and char.

Gas shale is productive in releasing natural gas when the surface areais exposed to other elements such as carbon dioxide. The greater theexposed surface area, the greater the efficiency and speed at which thegas is desorbed and released from the surface. Indeed, when gas shale isexposed to carbon dioxide, and carbon dioxide is adsorbed, methane gas(that has been adsorbed into the shale over time) will be desorbed andreleased.

Coals are sedimentary rocks containing more than 50 wt % organic matter,whereas gas shale contains less than 50 wt % organic matter. Methane isgenerated from the transformation of organic matter by bacterial(biogenic gas) and geochemical (thermogenic gas) processes duringburial. The gas is stored by multiple mechanisms including free gas inthe micropores and joints, and adsorbed gas on the internal surfaces ofthe organic matter. Nearly all coal bed gas is considered to be adsorbedgas, whereas gas shale is a combination of adsorbed gas and free gas.Free gas is the methane that is trapped within the pores or joints ofthe shale or coal structure.

True gas shale has adsorbed gas on the surfaces of the organic content,just like coal, as well as some free gas in the pore spaces and joints,unlike coal, which has virtually no macro-porosity. In such case,adsorbed gas is proportional to the total organic carbon (TOC) of thegas shale, and free gas is proportional to the effective porosity andgas saturation in the pores of the formation.

Gas shale has become an increasingly important source of natural gas inthe United States, and interest has spread to Canada and Europe. This isbecause gas shale is found in significant abundance in many areas of theworld and can be processed to produce natural gas using the abovedescribed hydraulic fracturing methods.

Typically, gas shale is a solid of low permeability, and therefore, gasproduction in commercial quantities requires fracturing to provideincreased permeability. While some formations may contain naturalfractures, for profitable production of natural gas from gas shale,modern technology is required, such as hydraulic fracturing andhorizontal drilling, etc.

Shale that hosts economic quantities of natural gas has a number ofcommon properties. They are rich in organic material, and are usuallymature petroleum source rock in a thermogenic gas window. They aresufficiently brittle and rigid enough to maintain open fractures andsome of the gas produced can be held in natural fractures, some in porespaces, and some adsorbed onto the surface of the organic material. Thegas in the fractures can be released immediately, whereas, the gasadsorbed onto organic material is typically released as the formationpressure declines.

Because gas shale normally has insufficient permeability to allowsignificant fluid flow from the formation to the well bore, for gasshale to become a profitable source of natural gas, it is important thatnew technologies be developed to improve its permeability. In fact, withthe advent of these new technologies, one analyst expects gas shale tosupply as much as half the natural gas production in North America by2020.

In gas shale formations, natural gas can sometimes be produced throughmore-permeable sand or silt layers inter-bedded with the shale, throughnatural fractures, or from the shale matrix itself. But in other cases,natural fractures are healed by a mineral filling and must be forcedopen by stimulation. It is also possible to have both shale and coalinter-bedded within a single reservoir, resulting in gas contributionsfrom both lithologies.

In U.S. Pat. No. 7,264,049, issued to Maguire, entitled “In situ methodof coal gasification,” an in-situ process for coal gasification usingliquefied gases and combustion of coal for heat release is provided.Maguire provides an in-situ process for coal gasification and theproduction of gas hydrates wherein a network of fractures is formed byinjecting liquefied gases such as nitrogen into a horizontally disposedfracturing borehole and allowing it to vaporize. The coal is thereafterignited and heated and the released pressurized gases are recovered fromthe fractured formations. One disadvantage of Maguire is that it teachesigniting coal and using combustion and heat to release pressurized gasfrom its fractures. Rather than using cold temperatures, as in thepresent invention, or pressure cycling with gas adsorption, Maguire usesheated temperatures to pressurize and release the gas from theunderground formation.

U.S. Pat. No. 4,374,545, issued to Bullen, et al., entitled, “CarbonDioxide Fracturing Process and Apparatus,” describes a method offracturing in an underground stratigraphic formation that is penetratedby a borehole. Liquefied gas and a proppant are pumped into theformation via the borehole pipe to induce fractures in the formation andthese fracture spaces are kept open by the proppant. Once injected, theliquid pressurized carbon dioxide is exposed to warmer temperatures,which causes the liquid to convert to a gas to induce furtherfracturing. The disadvantage of Bullen is that it uses proppants andchemicals that can raise environmental concerns.

One of the main contributors to global warming is believed to be theincrease in carbon dioxide gas emitted into the earth's atmosphere byvarious man-made activities and technologies such as coal burning powerplants. The main contributors to carbon dioxide emissions that canaffect the earth's atmosphere and therefore increase global warminginclude solid fuels, such as coal, liquid fuels, such as gasoline, andgaseous fuels, such as natural gas. While there is strong motivation touse coal for the generation of energy due to its efficiency andabundance, there is also a strong interest in eliminating the undesiredemission of carbon dioxide gas into the atmosphere which is caused bythe combustion of coal in standard coal combustion power plants.

One of the existing technologies used to eliminate excess carbon dioxideemissions involves “capturing” the CO₂ gas as it is being emitted fromsmokestacks and storing it. The idea of carbon capture and storage(CCS)—first introduced in the 1970's—began by making use of existingunderground reservoirs in which to store the CO₂ gas. The availablestorage space in underground reservoirs is probably large enough tostore all the carbon dioxide gas contained in all the remaining fossilfuel reserves throughout the world.

Recently, leading science and energy institutes advocated strongly forthe further development of carbon capture and storage technology. Forexample, capturing CO₂ from smokestacks is a practice that has existedfor years. Moreover, injection and storage of carbon dioxide gas isalready occurring in the North Sea, Algeria, and Texas.

While some of these technologies have gained credibility in recentyears, many experts still believe that because of the rapid use of theworld's remaining fossil fuel supplies, it is necessary to further lowerthe environmental impact caused by these technologies in an effort toprevent catastrophic climate changes in the future. The problem at handis that the process of capturing, transporting and storing carbondioxide gas from coal combustion power plants can dramatically raiseenergy consumption costs and cause serious health and environmentalissues and concerns. For example, if the energy used to capture CO₂emissions is derived directly from the fossil fuels themselves, thebenefits of capturing and storing the CO₂ will be offset by the verysame energy intensive process. And, if the energy comes from renewablesources, the technology would be rendered unnecessary as it would bemuch more efficient to generate electricity directly from the renewablesource.

Indeed, it has been discovered that capturing CO₂ from smokestacks andcompressing it for transport can be one of the most energy-intensiveaspects of the process. According to the International Panel of ClimateChange (IPCC), which prepared a comprehensive study, capturingtechnology (including compression of the gas for further transport andstorage) can raise the energy consumption of a coal combustion powerplant by an average of 32 percent.

Capturing carbon dioxide in rocks also requires a significantinfrastructure that is comparable to today's coal industry, which canalso lead to significant amounts of industrial wastes and miningtailings—for example, fuel ash from coal plants. The process alsogenerates large amounts of waste materials (apart from the carbonisedrocks themselves), and for every ton of carbon dioxide stored in rock,2.87 to 45.18 tons of disposable materials would be created.

For all of the above reasons, a new and improved method and apparatus isneeded for the capture and storage of CO₂ gases emitted from coalcombustion power plants, which can offset the high costs anddisadvantages associated with current carbon dioxide extraction andremoval methods, such that the world's coal reserves can be used withoutthe consequences of adding to man-made global climate changes, and thehigh cost of producing energy.

Moreover, for the above reasons, there is also a need to develop new andimproved technologies for increasing the permeability of coal and gasshale formations to make better use of the world's supply of naturalgas, including the gas stored in the pores and joints of the undergroundstrata and adsorbed onto the surface of rock formations, etc.

Nevertheless, there is also a need to develop improved technologies thatwill avoid the use of chemicals and the production of waste materials,etc., that can be harmful to the environment.

SUMMARY OF THE INVENTION

The present invention relates to a method and apparatus for capturingthe flue gas of a coal fired power plant, incinerator or chemicalprocessing plant, and separating the CO₂ gas therefrom, and convertingthe CO₂ gas captured from the power plant into a cold pressurized liquidCO₂, and injecting it under pressure into an underground stratum orlayer of coal and/or gas shale, and in particular, releasing thepressurized liquid CO₂ through perforations, and using it to createnarrow elongated fractures and openings within the layers, to increasethe formation's permeability, thereby increasing the flow of natural gasfound in the pores and joints therein, as well as increasing theadsorption of CO₂ and simultaneous desorption of CH₄, such that thenatural gases normally found within the formations can be released,recovered and sold to offset the overall cost of capturing andsequestering the CO₂.

CO₂ gas is preferably captured and separated from the flue gases of acoal burning power plant, incinerator, or chemical processing plant,using a standard process, such as one of the following: 1) Chemical andphysical absorption, 2) Solid physical adsorption—pressure swing andtemperature swing adsorption, 3) Low temperature distillation (cryogenicseparation); and 4) Membrane separation. In one method, an MEA chemicalabsorber is used to separate the CO₂ gas from the flue gases wherein thesystem comprises an absorber, a regenerating unit, a condenser, storagetank, and heat exchanger, etc. This chemical absorption system comprisesamine based processes for the removal of acid gas impurities (CO₂ andH₂S), wherein alkanolamines (MEA, DEA, and MDEA) are used to remove CO₂from the flue gas stream by the exothermic reaction of CO₂ with theamine functionality of the alkanolamine.

In another aspect, CO₂ gas can be separated and sequestered eitherbefore the coal is burned or afterwards, depending on the type ofequipment used. Technologies that can be used for this purpose aredisclosed in Applicants' related application Ser. No. 12/321,689,entitled “METHOD AND APPARATUS FOR REMOVING CARBON DIOXIDE GAS FROM COALCOMBUSTION POWER PLANTS,” which is incorporated herein by reference, andcan be used to separate gaseous carbon dioxide (also referred to asGCO₂) from the other elements, although any other method or apparatusfor CO₂ capture can be used.

The captured CO₂ gas is then pressurized, chilled and liquefied,although, if the CO₂ gas is chilled first, the CO₂ gas could form dryice. Thus, for optimal results, the CO₂ gas is preferably pressurizedfirst, prior to being chilled. For example, in the first step, the CO₂gas is preferably pressurized using a conventional compressor, butbecause the compression process heats the CO₂ gas, it must be cooled.Preferably, a first heat exchanger uses cold water circulated to coolthe pressurized CO₂ gas, and then, a second heat exchanger uses superchilled air produced by an associated turbo compressor and turboexpander set. Once the pressurized CO₂ gas (>100 psig) has beensufficiently chilled, such as down to minus 60 degrees F., it isconverted into a liquid (FIG. 7), and then preferably, the cold liquidCO₂ is fed into a cryogenic pump, to increase the pressure thereof, suchas up to 5,000 psia, depending on the conditions into which the liquidCO₂ will be injected.

The next step involves injecting the pressurized liquid CO₂ into theunderground coal or shale reservoir or formation using an array ofinjection pipes that extend down through the geological layers of rockuntil the targeted coal or gas shale layer is reached. The pipes arepreferably made of steel or other strong material and extended down intothe targeted layer where there are perforations for releasing andinjecting the liquid CO₂ directly into the rock formation. Theperforated portion of the pipe (preferably with small diametersubstantially horizontal holes) can extend vertically into a thickstratum or horizontally into a thin stratum of coal or shale thatcontain the adsorbed natural gas.

For any given site, the injection pipes are preferably spaced apart apredetermined distance from each other depending on the expected reachand effectiveness of the fracturing process to increase the permeabilityof the formation and therefore the efficiency of the process. To allowfor proper recovery of gas produced within the formation, similar arraysof recovery pipes are preferably extended into the geological layers toenable the gases to be released and recovered. Preferably, there aremore recovery pipes than injection pipes and recovery pipessubstantially surround the injection pipes. The specific pattern ofrecovery pipes can be predetermined to make efficient use of theequipment and geographic location.

Once the LCO₂ has been pressurized and chilled, it is ready to beinjected into the injection pipes and released into the strata. However,to avoid premature warming of the liquid CO₂, it is desirable to injectliquid nitrogen into the injection pipe first, which helps to pre-chillthe pipe, so that when the LCO₂ is injected, it will not change phase(to a gas) prematurely. Nevertheless, it is not expected that theinjection pipe will stay at the same temperature, and therefore, athermocouple is preferably provided to measure the temperature of thepipe and thus the extent to which the pipe is pre-chilled can becontrolled.

Initially, the LCO₂ is allowed to flow into the injection pipe and flashto GCO₂ until a steady state operation temperature can be reached, andthen, the cryogenic pump can be turned on to pressurize the LCO₂ downinto the formation which will continue until the predetermined pressureis reached, which can be up to 5,000 psia or more, depending on thecircumstances, measured at the bottom. Then, as the LCO₂ is releasedthrough the substantially horizontal perforations, the coal or shalewithin the formation will begin to break up and form fracturestherein—it will become rubblized—wherein long narrow substantiallyhorizontal passages are preferably created within the formation toincrease its permeability. As more liquid CO₂ is injected, and aspressure is increased, additional web-like fractures and patterns can becreated that can extend great distances, such as more than 1,000 feet,through the formation. Preferably, a shut off valve on each injectionpipe is provided, at the bottom, so that when the injection iscompleted, the injection pipes can be sealed.

By forcing the high pressure liquid CO₂ into the stratum via apre-chilled vertical pipe with an end extension of perforations, thepressurized LCO₂ is preferably vented through the perforations at abovethe fracture strength of the rock, thereby effectively creating holesand fractures in the formation and creating a long cavity of smalldiameter (pencil-like) openings extending substantially horizontally, inradial directions, from the perforated pipe. When the pressure exceedsthe fracture strength of the rock formation, the pressurized liquid CO₂is allowed to penetrate the shale or coal stratum with sufficient forceand speed to break up the formation. Not only does this help releasenatural gas trapped within the formation's pores and joints, but thebroken fragments can then be made more susceptible to adsorption ofGCO₂, and desorption of CH₄, such that more adsorption can take place,which means that more CO₂ can be sequestered, which also means that morenatural gas can be released and recovered from the site.

Because the underground formations tend to be warmer the deeper theyare, the newly exposed surfaces within the newly created openings andcracks of the formation will eventually cause the LCO₂ to warm.Likewise, pressurizing the LCO₂ can increase the temperature thereof,and when the cryogenic pump is shut down, the liquid pressure candecrease. Then, when the conditions are right, such as when the pressurein the matrix decreases to 400 psi, and the temperature increases toplus 40° F. (or any other point on the curve), the liquid LCO₂ suddenlychanges phase to a gas explosively, wherein the expansion of the GCO₂extends the reach of the cracks and creates more exposed surface areafor adsorption within the stratum. This process of rubblization exposesthe material in the product zone further by forming a multitude ofsmaller particles and a huge sum of exposed surfaces for the capture ofCO₂ and release of CH₄.

While it is preferable that this phase change occur after the pump isturned off, there is a possibility that the phase change could occurbefore the valves at the bottom of the pipes are sealed. This can dependon the depth of the formation, wherein, at greater depths, the pressureis greater, and therefore, the phase change will be less likely to occurprematurely, whereas, at shallower depths, the pressure will be less,and therefore, the phase change is more likely to occur as the LCO₂ iswarmed by its surroundings. In such case, a safety valve can be providedat the bottom to prevent the effects of the expansion to spread backinto the pipe. But regardless of where the expansion takes place, thissudden phase change occurs explosively and radiates fractures in alldirections, thereby increasing the volumes of fractures for furtheradsorption of CO₂ and desorption of CH₄.

Unlike previous hydraulic fracturing methods, there is no need for aproppant to maintain the width and openings of the fractures createdwithin the formation. This is because, normally a liquid is used, suchas water mixed with sand and other particulates and chemicals, and theproppants are needed to keep the fractures open while the liquid isallowed to pass. But in the present invention, no water is used, andbecause all of the LCO₂ is eventually converted into a gas, proppantsthat allow water to pass are not necessary. Also, one of the main goalsof the invention is for the CO₂ to be adsorbed onto the coal or gasshale fragments, wherein the CO₂ will be stored and sequestered withinthe formation once the fractures are opened. Indeed, portions of theLCO₂ within the cracks act as the proppants before the CO₂ is adsorbedonto the surfaces they are propping. Accordingly, for the time that thefractures remain open, natural gas preferably continues to be releasedand flow from the rock formation to the recovery well bores, such that asufficient amount of natural gas can be recovered to offset the cost ofcapturing and separating the CO₂ gas. The sequence of pressurization anddepressurization also enhances the migration of previously released lowdensity GCH₄ to pass through and/or over the high density GCO₂ and movetoward the recovery well bores during the subsequent pressurization anddepressurization cycle. In this respect, since the goal of sequesteringCO₂ is as important as the goal of collecting natural gas, the presentmethod is useful even if some of the natural gas released from the coalor shale remains trapped within the formation and remains unused. Thereis also no high volume of water and sand and no toxic additives usedduring the fracturing process, unlike previous methods.

With all bottom valves closed, penetration of the pressurized liquid CO₂through the formation is allowed to continue, and thus, furtherfracturing can occur, in which case, CH₄ can continue to be desorbed,and CO₂ can continue to be adsorbed, into the surfaces made free by thedesorption of CH₄. This containment is preferably sustained for aresidence period of time to permit the GCO₂ to be completely adsorbedand the lower density natural gas to migrate through the formation andinto the perforated recovery pipes through which the CH₄ can flow upwardto be extracted and collected.

After the appropriate waiting period, which can be about two weeks ormore, the valves at the bottom of the recovery pipes are preferablyopened slowly to allow pressure to remain in the formation as the gasesare released. If the pipes are opened too quickly, pressurized methanewill begin rising to the top, but large amounts of CO₂ may remainunderground within the formation without being adsorbed. By slowlyopening the valves, and slowly reducing the pressure again, low densityCH₄ is allowed to buoy past the heavy GCO₂ and allow the CH₄ to migrateto the recovery pipes, while at the same time, CO₂ continues to beadsorbed, and CH₄ to continues to be desorbed.

A preferred methodology for pressure cycling using the above describedprocesses, including the injection of cold liquid CO₂ into a coal orshale formation, involves using an injection well bore that is locatedat the center of several recovery well bores, such as those located atfour corners of a square. This 5-Point field entity is then repeated inall directions until the available acreage above the rock formation isfilled.

Each well bore preferably consists of an inner pipe surrounded by anouter pipe with a perforated section at the bottom extended down intothe matrix. There are preferably one or more valves at the bottom ofeach injection and recovery well bore which can be opened and closedduring the pressurized liquid CO₂ injection cycles.

The well bores preferably have three operational modes. 1) In the firstmode they can be used to dewater the formation in its nearby contactarea while the valves at the bottom of the well bores are open. 2) Whenthe dewatering is complete, liquid nitrogen and super-cold gaseousnitrogen are preferably used to chill the injection well bore (such asvia the inner pipe) while the valve at the bottom is closed. 3) Theliquid CO₂ is then introduced into the injection well bore (such as viathe inner pipe) while the valve at the bottom of the injection well boreis closed, such that pressure within the injection well bore can beincreased before it is released into the matrix.

In the first mode, the well bores can be used to dewater the undergroundmatrix, and after the formation has been pumped clear of water (such asover several months), methane may appear at the top such as via theannulus between the inner pipe and outer pipes. Pumping the water outstrongly reduces the local pressure in the matrix near the well bores,and weakly reduces the pressure in the matrix at further distances fromthe well bores. This reduction in pressure will create a pressuregradient, which in turn, causes the methane in the matrix to desorb andmigrate toward the well bores, wherein water and methane may appear atthe top. The water can then be processed and used or pumped to a pooland the methane can be collected or burned off. When the dewatering iscompleted, the water pumps are turned off and the well bores no longerpump water to the surface. The same process can be used to dewater boththe recovery and injection well bores.

When the injection well bores have been dewatered the next step involvesusing Liquid Nitrogen and/or Gaseous Nitrogen to chill the injectionpipes. The cryogenically cold liquid N₂ is preferably pumped down insidethe injection pipe with the bottom valve closed to chill the injectionpipe, but until a steady state temperature is reached, a change of phasemay initially occur, turning the liquid N₂ into cold gaseous N₂, whichwill need to be vented at the top. Note that using pipes with multiplelayers advantageously permits the air space within the annulus aroundthe inner pipe along the length of the outer pipe to interrupt theradially inward heat transfer flow.

After the inner pipe of the injection pipe is chilled in this manner,the flow of LCO₂ is preferably initiated within the injection pipe, suchas in the inner pipe. For example, the LCO₂ can be stored at 375 psigand minus 20° F. in a container above ground and can be sent downthrough the LN₂/LCO₂ heat exchanger to bring the LCO₂ (at >100 psig) tominus 60° F.

Initially, each vertical injection well bore is gravity-filled with LCO₂without using the cryogenic pump. At this point, the valve at the bottomof the injection well bore is preferably closed and the top vent isopen. Then, when GCO₂ bubbles stop coming to the surface, the cryogenicpump is preferably turned on and the top vent is closed to beginpressurizing the injection pipe with LCO₂. For example, to obtain afracture pressure of at least 4,000 psig, when using a 2,600 psigcryogenic pump, because the hydrostatic pressure associated with the5,000 feet depth of the injection pipe can contribute about 2,500 psigof pressure at the bottom, and the pump can contribute the remainder ofthe 2,600 psig, the total underground pressure can be brought to about5,000 psig or slighter more. Then, due to friction created by the lengthof the pipe, the actual pressure that releases the LCO₂ into the matrixcan be somewhere below 5,000 psig, but somewhere above 4,000 psig, toachieve the desired fracture strength.

Then, at the appropriate time, the valve at the bottom of the injectionwell bore is preferably opened and the pressurized liquid CO₂ is allowedto flow through the perforations and into the matrix, in which case, thepressurized liquid CO₂ begins to fracture and break up the matrix, suchas along the pipe perforation center line, which is preferablysubstantially horizontal due to the substantially horizontal orientationof the perforations. The pressure of the injected liquid CO₂ ispreferably far above the fracture strength of the matrix at theformation depth so that the jets create a penetrating flow of liquid CO₂(such as at close to 5,000 psig) within the matrix. The high speed andstresses of LCO₂ that exist preferably create rubble around the formedcavity, and fractures surrounding the solid bed. The valve at the bottomof the injection well bore is preferably opened slowly to avoid abruptpressure changes and to allow the jet streams of LCO₂ to gradually breakaway the matrix around the openings before full pressure is applied.

In this respect, it should be noted that the total release pressure willinclude, for example, 2,600 psig from the cryogenic pump, and 2,500 psigfrom the hydrostatic pressure head of the liquid CO₂ column at a depthof 5,000 feet, for a total of over 5,000 psig, i.e., the2,600+2,500=5,100 psig. Then, in this example, after taking into accountthe friction that exists along the length of the pipe, the actualpressure that drives the LCO₂ into the matrix will be an amount that isgreater than the fracture strength of the matrix, or 4,000 psig, butless than 5,000 psig. The length of the penetration of the LCO₂ isdetermined by the pressure gradient along the LCO₂ front and will extendfar into the formation until the tip of the perforation is no longerable to perforate the matrix.

The pressure is preferably maintained for a duration that is designed tohave the LCO₂ penetration crater extended radially toward the recoverywell bores but not completely reach the recovery well bores. Liquid CO₂is preferably injected at a rate such that the liquid CO₂ injected intothe cavity will cause the matrix to break up, and create penetratingholes or openings, which will fill the fractures in the bed matrix.After this round of releasing LCO₂ into the matrix, the valve at thebottom of the injection well bore is preferably closed. This is alsodone slowly to avoid creating too much pressure within the pipe thatcould result in a water hammer.

Then, preferably, with the bottom valve closed, no more liquid CO₂ willbe injected into the cavity until the pressure in the matrix decays toabout 200 psig. In this respect, it can be seen that as the LCO₂ isinjected into the matrix, and as new cleats are formed, the newlycreated cavities and openings within the formation creates a larger freevolume of space for the same mass of GCO₂ so that the matrix pressuredrops, such as to 200 psig, after a sufficient residence time. After the200 psig is attained, the next pressurization and depressurization cycleis preferably started. During this time, the relatively high temperatureof the matrix will eventually cause the extremely cold temperature ofthe liquid CO₂ to increase, wherein the LCO₂ will change phaseexplosively to a gaseous state which further breaks up the matrix.

With the bottom valve closed, the LCO₂ pressure within the injectionpipe can be increased again, and then, at the appropriate time, such aswhen the pressure within the matrix has dropped to below 200 psig, andsufficient LCO₂ pressure has built up inside the injection pipe, thevalve at the bottom of the injection well bore can be opened again andLCO₂ under pressure can be released into the matrix, thereby repeatingthe process. Then, when the matrix is suddenly exposed to the highpressure liquid CO₂ again, such as above the matrix compressivestrength, the crushing and fracturing caused thereby can overcome theinduced hoop stresses in the matrix, thereby creating additionalpenetrating holes and cracks which extend further into the matrix. Thehigh applied pressure preferably creates jets of liquid LCO₂ that can bedriven through the substantially horizontal cavities and openings thatwere previously formed by the earlier cycles, thereby creating longernarrow openings further and further toward the recovery well bores. Theliquid CO₂ also preferably spreads through the formation such as againstthe distal ends of the cavities, creating a plume of crushed material inits wake, wherein the liquid CO₂ preferably expands the proliferationzone which can then extend radially outward therefrom.

The specific pressure cycling steps involved are preferably as follows:

First, before the operation begins, the pump is turned off, and the topvent above the injection pipe is opened, and the valve at the bottomwhere the perforations are located is closed, which results in zeropressure being exerted into the well bore and therefore the matrix.

Second, liquid nitrogen is preferably injected into the well bore topre-chill the pipe which helps to regulate the temperature of the liquidCO₂ as it is being injected into the pipe, to avoid prematurevaporization and phase change of the liquid to a gas.

Third, a small amount of liquid CO₂ is preferably initially releasedinto the well bore to allow the pipe to reach a steady statetemperature, and then, the cryogenic pump is preferably turned on,leaving the top vent opened and the bottom valve closed. At this point,the pressure inside the well bore begins to increase, both from thecolumn of liquid CO₂ filling the pipe, and the pressure of the CO₂ beinginjected into the pipe.

Fourth, when liquid CO₂ begins overflowing from the top vent, and thegas bubbles stop rising to the top, the top vent above the injectionwell bore is preferably closed, and the pump is turned to full power toinject more liquid CO₂ into the pipe, with the bottom valve closed. Thispreferably continues to increase the pressure inside the injection wellbore until the desired maximum pressure is reached, which is determinedby the combination of the pressure head created by the liquid CO₂ columninside the pipe, and the pressure of the CO₂ created by the pump.

Fifth, once the desired maximum pressure inside the injection pipe isreached, with the pump on and the top vent closed, the system is readyto release the pressurized liquid CO₂ into the matrix, wherein the valveat the bottom is preferably opened, thus causing pressurized jet streamsof liquid CO₂ to be released through the perforations and into thematrix. Preferably, the valve is opened slowly to avoid sudden pressurechanges in the pipe, and to gradually induce fracturing at asubstantially steady pace, and once the valve is opened fully, the speedand pressure created by the jet streams help break up the formation andcreate fractures, openings and holes extending substantiallyhorizontally through it. The preferred typical speed of flow through theperforations is 100 ft/sec and up to 500 ft./sec. or higher.

Sixth, as the liquid CO₂ is released, the pressure inside the pipebegins to drop gradually, but with the pump on and the liquid CO₂continuing to be injected into the well bore, the pressurized flowthrough the perforations can be substantially maintained, such that theforce and pressure of the liquid CO₂ jet streams can continue to breakup the matrix.

Seventh, as the liquid CO₂ continues to flow through the perforations,and the pressure continues to drop, at a predetermined time, the pump ispreferably stopped and the bottom valve is preferably closed. The topvent is also preferably opened. At the same time, as the liquid CO₂continues to proliferate into the matrix, the LCO₂ becomes exposed tothe warmer temperature of the rock formation, wherein, at some point,the liquid CO₂ changes phase and vaporizes explosively, creating up to20,000 psig or more of pressure, thereby breaking up the formationfurther and forming greater fractures and openings, further downstreamfrom the injection well bores, toward the recovery well bores. Therelatively high temperature of the matrix raises the temperature of theextremely cold liquid CO₂, wherein the LCO₂ will eventually change phaseto a gas, such as when the pressure drops a sufficient degree.

Eighth, with the pump off, and the bottom valve closed, the gaseous CO₂will continue to proliferate into the matrix, and the process ofadsorption of CO₂ and desorption of CH₄ will continue. Then, preferably,with the bottom valve closed, and with no more liquid CO₂ being injectedinto the matrix, the pressure within the matrix will decay, and will doso quickly at first, because of the additional cleats and spaces thathave been formed in the matrices, and then, more slowly as the GCO₂migrates through the available pores in the matrix between the cavityand the recovery well bores, and eventually, the pressure is preferablyallowed to drop to about 200 psig.

With the bottom valve closed, the pressure within the well bore can thenbe increased again by turning on the pump and closing the top vent, asdiscussed above, and the cycle can be repeated. Then, at the appropriatetime, such as when the pressure within the matrix has dropped to below200 psig, and sufficient LCO₂ pressure has built up inside the injectionpipe, the valve at the bottom can be opened again and pressurized LCO₂can be released back into the matrix, and the cycle can be repeatedagain. Then, at the appropriate time, the valve at the bottom of theinjection pipe can be closed again, and the pressure of the liquid CO₂in the matrix can be allowed to drop again. At that point, the matrixtemperature can be anywhere between −20° F. and +10° F., and when thepressure within the matrix drops to about 200 to 300 psig, the liquidCO₂ may flash explosively again into gaseous CO₂ causing furtherpenetration into the more distal portions of the matrix.

Through these repeated cycles, the matrix can continue to be broken up,the CO₂ gas can continue to be adsorbed, the CH₄ gas can continue to bedesorbed, and the released CH₄ can continue to be pushed ahead of theadvancing CO₂ front and toward the recovery well bores. In this respect,the relatively high pressure field created near the injection well boresby the emission of pressurized LCO₂ will tend to cause the released CH₄to travel toward the relatively low pressure field that exists near therecovery well bores. And as the pressure drops further away from theinjection well bores, more CO₂ will tend to be adsorbed, and more CH₄will tend to be desorbed, consistent with Langmuir's isotherm. Thus,allowing the pressure to drop further, as well as allowing thetemperatures created by the liquid CO₂ to drop, enables more adsorptionto occur. Eventually, the leading edge of the released CH₄ cloud willreach the recovery well bores and the CH₄ gas can then be pumped upthrough the recovery pipes and extracted and collected at the surface.By its very nature, CH₄ is lighter in molecular weight than GCO₂, sobetween the two, CH₄ will tend to rise and GCO₂ will tend to drop. Thisprocess may continue until much of the released CH₄ from the formationis recovered, which can take several years.

In latter cycles, or after the final cycle, the bottom valves can beopened and closed again and configured to release high speed liquidslugs of LCO₂ that can fly through the GCO₂ vapor, such as within thesubstantially horizontal cavities and spaces that were previously formedby the earlier cycles, to impact the distal ends of the cavities andcreate over 20,000 psig of impact pressure, which further helps create alonger fracture zone that can be expanded over time. In this respect,the repeated injection of liquid CO₂ as jet streams and/or high speedslugs helps to break down the structure of the matrix, creating longnarrow proliferation zones, which in the past had to be accomplished bymore expensive methods such as extending long horizontal pipes throughthe formation.

This pressure cycling process can be repeated multiple times, such asover the course of multiple years, to further enhance the break-up ofthe formation and further enhance the ability of the formation torelease its methane gas. This way, more of the matrix can be exposed toCO₂ due to higher permeability, which in turn, enables greateradsorption of CO₂ and desorption of CH₄. This induced pressure cyclingmethod advantageously compresses the cleats and cleat spaces underrelatively high pressure, but then when the pressure is reduced, thecleats are relieved and then expanded, wherein, switching between highand low pressures can help to enhance the ability of the formation tobreak up and release the CH₄. This pressure cycling method has theadvantage of using relatively high pressure to fracture the formation tocreate new cleats, and of using relatively low pressure to allow thecleats to expand, which also enhances the ability of the gases to beadsorbed and desorbed through the use of lower pressure.

In addition to the existence of lower pressure phases during cycling,the cold temperature of the CO₂ (preferably kept to below +10° F.) alsoenhances the rate at which the CO₂ is adsorbed onto the exposed surfacesthat simultaneously desorbs CH₄ into the volume within the cleats andpores. The molecular adsorption and desorption exchange within thematrix takes place more efficiently at lower temperatures, and lowerpressures, wherein adsorption/desorption becomes accelerated.

Once the cycles are completed, the recovered CH₄ can be extracted andcollected from the recovery pipes and transported via pipe or truck,etc., and used, such as injected in natural gas pipelines for resale,used as an industrial feedstock, or used for heating and electricitygeneration, etc. Then, the same process can be repeated, or the pump canbe connected to another injection pipe at another location, so that theprocess can be performed in a new site.

When this process is used in connection with a coal bed, one option isto leave the formation in place after the CH₄ has been removed, and theCO₂ has been sequestered and stored underground. This has the advantageof using CH₄ while helping to sequester the CO₂ underground to protectthe environment. Another option is to mine the coal after the CH₄ hasbeen removed, in which case, because explosive CH₄ has been removed fromthe site, the risk of dangerous explosions occurring is significantlyreduced. At the same time, mining will eventually expose the adsorbedCO₂ to atmospheric pressure, in which case, the GCO₂ that was previouslyadsorbed into the formation will be released back into the atmosphere.Thus, the method described above can be used for sequestering CO₂ andproducing useful CH₄, or it can also be used for producing CH₄ andpreparing underground coal formations for safe mining purposes.

One of the objectives of the present method and apparatus is to enablethe coal or gas shale formation to be exposed to CO₂ within the joints,cracks, fissures and fractures of the rock formation, so that the CO₂molecules will be adsorbed onto the fragments, whereas, the CH₄molecules will be desorbed and released, such that the released naturalgas can be made available by migrating toward the nearby recovery wellbores and buoy itself upward through the pipe to the surface. As aconsequence, the CO₂ can be sequestered and stored in the formation,whereas, the CH₄ can be released and used. The methodologies andapparatuses described herein can be altered without departing from thepresent invention.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic drawing showing a system for capturing andseparating CO₂ gas from the flue gas of a coal burning power plant;

FIG. 2 is a schematic drawing showing an alternate system for capturingand separating CO₂ gas from the flue gas of a coal burning power plant;

FIG. 3 is a schematic drawing showing another system for capturing andseparating CO₂ gas from the flue gas of a coal burning power plant;

FIG. 4 is a schematic drawing showing a system for producing superchilled air using a turbo compressor and turbo expander set;

FIG. 5 is a chart showing the various pressure and temperature levelsthat occur using the apparatus shown in FIG. 4 to produce super chilledair;

FIG. 6 is a schematic drawing showing a system for pressurizing andchilling the CO₂ gas captured from the flue gas of a coal burning powerplant, wherein two heat exchangers are shown, one using cold water, andthe other using chilled air produced by the system shown in FIG. 4,along with a cryogenic pump;

FIG. 7 is a phase chart for carbon dioxide in vapor, liquid and solidphases, showing the temperature and pressure amounts that are requiredfor those phases;

FIG. 8 is a diagram showing the pressure and temperature of CO₂ atvarious stages within the method;

FIG. 9 is a schematic drawing showing CO₂ being adsorbed onto coal andCH₄ being desorbed;

FIG. 10 is a schematic drawing showing the before, during and aftersteps relating to how CO₂ is adsorbed and CH₄ is desorbed and releasedfrom coal or shale;

FIG. 11 shows a cross section of a typical abandoned coal mine showinghow the input/injection pipes and output/recovery pipes are positionedwithin the underground strata;

FIG. 12 shows a cross section of a typical coal or gas shale siteshowing how the input/injection and output/recovery pipes are positionedwithin the underground strata or layer;

FIG. 13 shows a cross section of a typical coal or gas shale siteshowing how the input/injection and output/recovery pipes are positionedwithin the underground strata or layer, wherein the lower end of theinput/injection pipe is extended horizontally;

FIG. 14 shows in plan view a typical input/injection pipe within a coalor gas shale formation with four narrow directional voids created by thehigh pressure liquid CO₂ injected through four perforations in the pipe,and the web-like fractures they create;

FIG. 15 shows in plan view a typical coal or gas shale site showing howthe arrays of input/injection and output/recovery pipes are locatedrelative to each other, and how the narrow voids created by thepressurized liquid CO₂ injections from each perforation in eachinput/injection pipe are oriented, wherein the different grids areoffset to allow the voids to intermesh with each other, to allow morearea to be covered by each input/injection pipe;

FIG. 16 shows another plan view of the coal or gas shale site shown inFIG. 15;

FIG. 17 shows a cross section of a typical coal or gas shale siteshowing how the input/injection and output/recovery pipes are positionedwithin the underground strata, wherein the pressurized cold liquid CO₂injected through each perforation within each input/injection pipe formshorizontally directed voids that extend laterally through the formation,as well as extended web-like fractures extending above and below thevoids throughout the formation;

FIG. 18 shows a similar cross section of the site shown in FIG. 17, butin this drawing, the pipes are closed at the top;

FIG. 19 shows a similar cross section of the site shown in FIG. 17, butin this drawing, the pipes are open;

FIG. 20 shows a cross section of a pipe showing how the CH₄ rises andthe CO₂ falls due to their relative densities;

FIG. 21 is a chart showing the relative densities of CH₄ and CO₂ atdifferent pressures and at 40 degrees F.;

FIGS. 22 and 23 show in plan view two different patterns of arrays ofinput and output pipes for a single location, where the top one has 36wells in each direction, and the bottom one has 22 wells in eachdirection;

FIG. 24 shows a cross section of a typical pipe extending down into thegas bearing strata through the soil and layers above;

FIG. 25 shows a cross section of an alternate injection pipe embodimenthaving inner and outer pipes and valves at the bottom for injectingliquid CO₂ into a coal or shale formation;

FIG. 26 shows the alternate injection pipe embodiment of FIG. 25 withtanks and devices for delivering the liquid nitrogen and LCO₂ into theinjection pipe;

FIG. 27 shows a cross section of an alternate recovery pipe embodimenthaving inner and outer pipes and valves at the bottom for recoveringmethane from a coal or shale formation;

FIG. 28 is a chart showing the greater efficiency that results inadsorption of CO₂ onto granulated coal and desorption of CH₄ resultingfrom exposing the coal matrix to lower temperatures of CO₂;

FIG. 29 is a chart showing the amount of pressure that exists inside theinjection pipe over time, at the top and at the bottom of the pipe,during the pressure cycling steps, including when the pump is turned on,when the top vents are opened and closed, and when the bottom valves areopened and closed;

FIG. 30 is a chart showing the amount of pressure that exists inside thecoal or shale gas matrix just outside the injection pipe over timeduring the pressure cycling steps, including when the bottom valves areopened and closed, and when the liquid CO₂ changes phase into a gaseousCO₂;

FIG. 31 is a chart showing the increased permeability of coal resultingfrom using the pressure cycling methods and processes described herein;

FIG. 32 is a chart showing the enhanced ability of the methods andprocesses described herein to recover natural gas from a coal bedcompared to other methods and processes;

FIG. 33 is a schematic side elevation view showing an embodiment of aninjection pipe extending down to a depth of 5,270 feet, with a pump andvent at the top, and a valve at the bottom, with the pump off, the ventopen and the valve closed, showing zero pressure inside the pipe, whichrepresents the status of the system at time T1;

FIG. 34 is a schematic side elevation view showing an embodiment of aninjection pipe extending down to a depth of 5,270 feet, with a pump andvent at the top, and a valve at the bottom, with the pump on, the ventopen and the valve closed, showing zero pressure inside the pipe, whichrepresents the status of the system at time T2;

FIG. 35 is a schematic side elevation view showing an embodiment of aninjection pipe extending down to a depth of 5,270 feet, with a pump andvent at the top, and a valve at the bottom, with the pump on, the ventopen and the valve closed, showing 2,598 psig inside the pipe at thebottom, which is the pressure head of the liquid CO₂ column inside thepipe, which represents the status of the system at time T3;

FIG. 36 is a schematic side elevation view showing an embodiment of aninjection pipe extending down to a depth of 5,270 feet, with a pump andvent at the top, and a valve at the bottom, with the pump on, the topvent closed and the bottom valve closed, showing 5,200 psig inside thepipe at the bottom, which is exerted by a combination of the pumppressure (of about 2,600 psig) and the pressure head of the liquid CO₂column inside the pipe (of about 2,600 psig), which represents thestatus of the system at time T4;

FIG. 37 is a schematic elevation view showing the bottom of an injectionpipe extending down into a coal or shale matrix, with the pump on, thetop vent closed and the bottom valve opened, showing liquid CO₂ beinginjected through the perforations, wherein a jet stream of liquid CO₂ isinjected into the matrix, which represents the status of the system attime T5;

FIG. 38 is a schematic elevation view showing the bottom of an injectionpipe extending down into a coal or shale matrix, with the pump off, thetop vent opened and the bottom valve closed, showing the disseminationand proliferation of liquid CO₂ that continues into the matrix evenafter the bottom valve is closed, wherein the liquid CO₂ continues toflow through the matrix, but wherein the pressure within the matrixbegins to drop as the crushing region expands, which represents thestatus of the system at time T6;

FIG. 39 is a schematic elevation view showing the bottom of an injectionpipe extending down into a coal or shale matrix, with the pump off, thetop vent open and the bottom valve closed, showing the liquid CO₂ beingwarmed and changing phase explosively into a gaseous CO₂, creatingpressure within the matrix of up to 20,000 psig, wherein the gaseous CO₂further penetrates and expands into the fracture region, whichrepresents the status of the system at time T7;

FIG. 40 is a schematic elevation view showing the bottom of an injectionpipe extending down into a coal or shale matrix, with the pump off, thetop vent open and the bottom valve closed, showing the pressure withinthe matrix dropping, such as down to 15,000 psig, as the gaseous CO₂further penetrates and expands into the fracture region, whichrepresents the status of the system at time T8;

FIG. 41 is a schematic elevation view showing the bottom of an injectionpipe extending down into a coal or shale matrix, with the pump off, thetop vent open and the bottom valve closed, showing the pressure withinthe matrix continuing to drop, such as down to 7,500 psig, as thegaseous CO₂ further penetrates and expands into the fracture region,wherein the GCO₂ is adsorbed and GCH₄ is desorbed, which represents thestatus of the system at time T9;

FIG. 42 is a schematic elevation view showing the bottom of an injectionpipe extending down into a coal or shale matrix, with the pump off, thetop vent open and the bottom valve closed, showing the pressure withinthe matrix continuing to drop, such as all the way down to 200 psig, asthe gaseous CO₂ further penetrates and expands into the fracture region,wherein the GCO₂ continues to be adsorbed and the GCH₄ continues to bedesorbed, wherein twice as much GCO₂ is adsorbed than GCH₄ is desorbed,which represents the status of the system at time T10; and

FIGS. 43 to 44 are two schematic elevation views showing the bottom ofan injection pipe extending down into a coal or shale matrix, at a latertime, such as after the pressure cycles have been repeated, whereincavities and fractures have already been formed within the matrix,wherein these views show the penetration of an additional volume ofliquid CO₂ stream (finite length, free flying liquid slug) beinginjected into the matrix through the perforations, by opening andclosing the valves again, wherein the stream further penetrates into andexpands the fracture region by reaching further into the existingcavities and fractures toward and against their distal ends.

DETAILED DESCRIPTION OF THE INVENTION

The proposed approach preferably comprises capturing, pressurizing,chilling and liquefying the CO₂ effluent from a coal fired power plant,incinerator or chemical processing plant and then introducing thepressurized CO₂ in liquid form (LCO₂) into a coal stratum or a gas shalestratum that will sequester the LCO₂. There will also be natural gasrecovered from the site including after the CO₂ has been adsorbed intothe coal or shale and natural gas has been released therefrom, which canbe sold to offset the cost of sequestering the CO₂. If these strata arelocated adjacent to the power plant, the LCO₂ is preferably directlyinserted into the strata. If these strata are located a distance fromthe power plant, the captured CO₂ is preferably collected onto a trucktrailer or into a pipeline, etc., for transport to the strata site. Ineither case, natural gas can be recovered for sale.

Separation of carbon dioxide gas (CO₂) from the flue gases of a powerplant, incinerator or chemical processing plant can be accomplished in avariety of ways. For example, the MEA chemical absorber technique forseparating CO₂ from flue gases can be performed efficiently by the useof high mass flow of super chilled air wherein the flue gases arepressurized and then passed through the tubes of a heat exchanger withina shell of super chilled air. For post combustion CO₂ separation thereare several approaches available, including: 1) Chemical and physicalabsorption, 2) Solid physical adsorption—pressure swing and temperatureswing adsorption, 3) Low temperature distillation (cryogenicseparation); and 4) Membrane separation.

The chemical absorption process for separating CO₂ from flue gascomprises amine based processes that have been used commercially for theremoval of acid gas impurities (CO₂ and H₂S) from process gas streams.Alkanolamines can remove CO₂ from the flue gas stream by the exothermicreaction of CO₂ with the amine functionality of the alkanolamine.Different amines have different reaction rates with respect to thevarious acid gases. In addition, different amines vary in theirequilibrium absorption characteristics for the various acid gases andhave different sensitivities with respect to solvent stability andcorrosion factors.

Alkanolamines can be divided into three groups: (1) primary amines whosemembers include monoethanol amine (MEA), diglycolamine (DGA); (2)secondary amines whose members include diethanolamine (DEA),di-isopropylamine (DIPA); and (3) tertiary amines whose members includetriethanolamine (TEA) and methyl-diethanolamine (MDEA).

FIG. 1 shows a gas amine absorption system that can be used inconnection with the process described herein. In the amine gasprocessing operation, the cooled flue gas flow 3 is preferablyintroduced into the absorber 5 (absorption tower), wherein the gasstream and liquid amine solution are preferably mixed by acountercurrent flow within absorber 5. Preferably, the gas 3 to bescrubbed enters the absorber 5 at the bottom, flows up, and leavesabsorber 5 as an exit gas 11 (rich in N₂ and O₂) at the top, whereas,the solvent 7 enters the top of the absorber 5, flows down (contactingthe gas), and emerges at the bottom 9. Dilution of the circulating aminewith water is preferably accomplished to reduce the viscosity of thecirculating fluid. The liquid amine solution 9 containing the absorbedgas is then pumped (using a CO₂ rich amine pump 13) through a lean/richheat exchanger 15, where it is heated, and then the solution is fed intoa stripper or regeneration unit 19 where the acid gases are liberated.Solvent regeneration can be carried out at low pressures to enhancedesorption of CO₂ from the liquid.

The acid gas stream 21 containing the CO₂ preferably leaves theregeneration unit 19, wherein some amine solution is typically carriedover from the regeneration step, wherein the amine solution ispreferably recovered using a condenser 23. After passing through areflux drum 20, the separated CO₂ gas 24 is then recovered and captured,such as for dehydration and compression, etc., wherein the remainingamine solution 26 is returned to regeneration unit 19. The expelled hotlean amine solution 25 is then passed through a reboiler 27, and pumpedby lean amine pump 22 back to heat exchanger 15, where it is contactedwith the rich amine solution from absorber 5, and from there the leanamine solution is returned back to absorber 5.

Among the primary amines, MEA has been the traditional solvent of choicefor carbon dioxide absorption and acid gas removal. MEA is the leastexpensive of the alkanolamines and has the lowest molecular weight, soit possesses the highest theoretical absorption capacity for carbondioxide, although this theoretical upper absorption capacity of MEA isnot realized in practice due to corrosion problems. In addition, MEA hasthe highest vapor pressure of any of the alkanolamines and high solventcarryover can occur during carbon dioxide removal from the gas streamand regeneration step. To reduce solvent losses, a water wash ofpurified gas stream is usually required. In addition, MEA reactsirreversibly with minor impurities such as COS and CS₂ resulting insolvent degradation. Foaming of the absorbing liquid MEA due to thebuild-up of impurities can also be a concern.

There is considerable industrial experience with MEA and most systems atpresent use an aqueous solution with 15-25-wt % MEA, mainly due tocorrosion issues, although corrosion inhibitors may be added whichresults in an increase in solution strength. In a commercial process,concentrations of MEA up to 30-wt % have been employed successfully toremove 80% to 90% of the carbon dioxide from the feed gas. The processhas been used to treat flue gas, although some cooling and compressionof the gas is required to operate the system. Another commercialprocess, which uses 20% MEA with inhibitors, is also offered for fluegas treatment.

For the current MEA absorber systems, the adsorption and desorptionrates are reasonably high. However, the column packing represents asignificant cost, and its energy consumption is also significant forflue gas treatment. In addition, the stripping temperature should not betoo high. Otherwise, dimerization of carbamate may take place,deteriorating the sorption capability of MEA.

To date, commercial CO₂ capture plants typically use processes based onchemical absorption. The typical size of a commercial plant isrelatively small (with a maximum of 800 tons/day) compared to thatrequired for processing power plant flue gases (more than 5,000tons/day).

The greatest limitation for CO₂ recovery from flue gas is its lowpressure. CO₂ is absorbed much more easily into solvents at highpressure. The only commercially available solvents that can absorb areasonable amount of CO₂ from dilute atmospheric pressure gas areprimary and sterically hindered amines, such as MEA, DGA and KS-1, KS-2and KS-3 series of solvents. These solvents can absorb CO₂ at lowpressures because they have high reaction energies. This results inhigh-energy requirements to regenerate the rich solvent. However, energycosts may be reduced if the process can be fully integrated with a powerplant where significant amount of low-grade heat may be available.

Flue gas entering the absorber at high temperatures can lead to solventdegradation and decreased absorption efficiency. Thus, the flue gasshould be cooled to a water dew point of 50 degrees C., which can beaccomplished in the desulfurization unit or with a direct contact watercooler.

Another system that can be used is shown in FIG. 2, which is based uponthe use of amine solvents, principally monoethanolamine (MEA), developedoriginally to treat sour gas containing hydrogen sulfide. In thissystem, the MEA contacts the flue gas in an absorber 30 and takes up theCO₂, which is then subsequently steam-stripped in stripper 32 to releaserelatively pure carbon dioxide. The major components of this systeminclude an absorber 30, regenerator (stripper) 32, solvent storage tank34, heat exchanger 36, CO₂ condenser 38, and booster pump 40.

In use, the flue gas stream enters at the left side of FIG. 2. Thechemical solvent and CO₂ are exposed to one another in absorber 30 wherethey react chemically to form the loosely bonded intermediate compound.This compound, in liquid form, is then isolated and transferred to heatexchanger 36 and regenerator (also called stripper) 32 where it isheated, causing it to break down into separate streams of CO₂ andsolvent. The CO₂ is then condensed in the condenser 38 and sent forfurther processing, such as dehydration and compression, before it isready for storage or commercial use. The solvent stream produced in theregenerator 32 is then recycled back to the absorber 30 and the processrepeats.

Note that storage tank 34 is installed in the solvent return line toallow for constant CO₂ removal under varying solvent recycling rates.Booster pump 40 also provides the pressure gradient required totransport the solvent. The heat exchanger 36 captures waste heat bytransferring heat from the relatively hot fluid returning from theregenerator 32 to the relatively cool fluid flowing to the regenerator32.

The chemical absorption process produces a relatively pure carbondioxide stream, although one disadvantage of the process is that itconsumes a significant amount of energy which is typically produced bythe power plant.

The chemical absorption process preferably uses pressure vessels,storage tanks, pumps, and heat exchangers similar to those used in manyother industrial processes. The absorber module is preferably agas/liquid contactor located within a carbon steel vessel or duct. Thiscomponent can be similar to the wet scrubber modules retrofitted ontomany coal-fired power plants to reduce sulfur emissions. Duringoperation the absorber module pressure and temperature are approximatelyequal to those of the exhaust entering the module. Unlike the wetscrubber, there is no significant waste product generated in theabsorber module. Another similar but more complicated system is shown inFIG. 3.

Another method of capturing CO₂ gas involves low temperaturedistillation (cryogenic separation) which is a process commonly used toliquefy and purify CO₂ from relatively high purity (>90%) sources. Ittypically involves cooling the gases to a very low temperature so thatthe CO₂ can be liquefied and separated.

Distillation generally has good economies of scale and is worthconsidering where there is a high concentration of CO₂ in the waste gas.The advantage of this method is that it produces a liquid CO₂ ready fortransportation by pipeline or storage or other use as specified herein.The major disadvantages of this process are the amount of energyrequired to provide the refrigeration and the necessary removal ofcomponents that have freezing points above normal operating temperaturesto avoid freezing and eventual blockage of the process equipment.

For post combustion flue gases, the waste streams typically containwater and other trace combustion by-products such as NOx and SOx severalof which must be removed before the stream is reduced to a lowtemperature. Moreover, these by-products are usually generated nearatmospheric pressure and tend to make cryogenic processes lesseconomical than others in separating CO₂.

FIG. 4 shows an example of a system 42 that can be used to produce superchilled air which in turn can be used to reduce the temperature of theCO₂ gas recovered through the previously described CO₂ captureprocesses. FIG. 4 is a schematic drawing showing an embodiment thatutilizes a two stage turbo compressor and two stage turbo expander set,wherein the turbo compressor and turbo expander are located on a commonshaft, and multiple heat exchangers are provided.

As seen in FIG. 4, system 42 has a two stage turbo compressor 44, 46,and a two stage turbo expander 48, 50, along with two heat exchangers,52, 54. It can be seen that the ambient air 41 (or previously compressedair) is introduced and first acted upon by first turbo compressor 44which compresses the air, wherein a first heat exchanger 52 reduces thetemperature thereof. The air that has been compressed is then acted uponby second turbo compressor 46 which compresses the air again, wherein asecond heat exchanger 54 reduces the temperature again. These arefollowed by first and second turbo expanders 48, 50, which expand andrelease the compressed air to produce super chilled air.

In use, the input air 41 is preferably introduced at step one (shown inboxes) into first stage turbo compressor 44, wherein the air isinitially compressed. At this point, the air can be compressed, such asto about 90 to 125 psia, which also increases the temperature of theair, such as from 70 degrees F. to about 135 degrees F., or more, asshown in FIG. 5. However, because first turbo compressor 44 is not fullyefficient, the compressed air does not achieve a maximum temperature.For example, there may be losses (as shown in FIG. 5), wherein theoutput temperature may be less.

The compressed air that exits turbo compressor 44 at step two is thenpreferably passed through first heat exchanger 52, wherein thetemperature of the compressed air is reduced. First heat exchanger 52can be any conventional type that draws heat away from the compressedair. Preferably, the temperature of the compressed air can besubstantially reduced such as down to room temperature before it ispassed onto second stage turbo compressor 46 at step three. Although thepressure of the compressed air preferably remains about the same, someminimal pressure drop may be caused by the flow of air through theinterior of heat exchanger 52.

Next, the compressed air that exits first heat exchanger 52 ispreferably introduced at step three into second stage turbo compressor46, wherein the air is compressed further. For example, at this point,the air is preferably compressed to an even higher pressure, i.e., about220 psia or more, which also increases the temperature of the air, asshown in FIG. 5. However, because second turbo compressor 46 is notfully efficient, the compressed air does not achieve maximumtemperature.

The compressed air that exits second stage turbo compressor 46 at stepfour is then preferably passed through second heat exchanger 54, whereinthe temperature of the compressed heated air is reduced again. Secondheat exchanger 54 can be any conventional type that draws heat away fromthe air. The compressed air that exits second heat exchanger 54 at stepfive is then introduced into first stage turbo expander 48, wherein thecompressed air is released and expanded. For example, at this point, theair which has been compressed to about 220 psia can be released untilthe pressure is reduced to about 55 psia, wherein the temperature can besignificantly reduced, such as down to minus 80 degrees F., as shown inFIG. 5. The air that exits first stage turbo expander 48 at step six isthen introduced into second stage turbo expander 50, wherein the air isreleased and expanded again, to step seven. For example, at this point,the air which was at 55 psia can be released until the pressure isreduced down to ambient pressure, and the temperature can be reducedfurther, such as down to minus 170 degrees F. to minus 185 degrees F.,although due to losses, the actual output temperature may not be as low.

It should be noted that as air is passed through system 42, as describedabove, and as turbo expanders 48 and 50 begin to spin and operate torelease the compressed air, additional work is performed whicheventually results in the system reaching a steady state condition ofoperation. The basic operation of device 42 starts with air beingintroduced into first stage turbo compressor 44, and then, into secondstage turbo compressor 46, and by the time the compressed air isreleased, because turbo expander 48 and turbo compressor 44, and turboexpander 50 and turbo compressor 46 are located on the same shaft, whenturbo expanders 48, 50 begin to rotate, turbo compressors 44, 46 alsobegin to rotate. As this occurs, all four begin rotating in unison. Acommon shaft 56 (“free spindle”) that extends between turbo compressors44, 46 and turbo expanders 48, 50, respectively, enables the torque(mechanical work) generated by turbo expanders 48, 50 to drive turbocompressors 44, 46, until a steady state condition of operation isachieved. In this system, electricity is not generated, although it canbe. This is only one system that can be used to produce chilled air inconnection with the invention contemplated—others can be used as well.

FIG. 6 shows a cryogenic pump system 60 used to pressurize, chill andliquefy the GCO₂ captured from the flue gas to form a pressurized coldliquid CO₂, using cold water and the super-chilled air produced bydevice 42. System 60 preferably comprises a compressor 62, a first heatexchanger 64, second heat exchanger 66, and cryogenic pump 68. Thepresent method involves exposing the gaseous CO₂ to the high mass flowof super chilled air to form liquid carbon dioxide using system 60.

If the GCO₂ is fed directly to a heat exchanger and chilled atatmospheric pressure, the GCO₂ could form “dry ice”. Thus, it is firstdesirable to pressurize the GCO₂ prior to chilling it. For example, inthe first step, the room temperature GCO₂ at ambient 1 atmosphericpressure is preferably pressurized, such as to GCO₂ at 17 atmospheres(250 psia), using compressor 62. But because the compression processwarms the compressor body, the compression process also produces heatedGCO₂ that must be cooled, which can be accomplished by using heatexchanger 64—slightly pressurized water is passed through the shell 67of the heat exchanger 64 and the highly pressurized GCO₂ is passedthrough the multitude of small diameter tubes 65. The small diameter oftubes 65 permits containment of the high pressure GCO₂, and the largequantity of tubes provides the necessary surface area for the heattransfer to occur between the water and GCO₂. Baffles 69 help increasethe path length of the coolant water in the fixed length of the heatexchanger shell 67. Through this process, there is a pressure drop inthe GCO₂ caused by the flow of the GCO₂ through the tubes over a longpath length.

The GCO₂ is next passed through the second heat exchanger 66 wherein thesuper-chilled air is preferably passed through the shell 67 of heatexchanger 66, while the high pressure GCO₂ is passed through the smalldiameter tubes 65 over a long path length. It is in these heat exchangertubes 65 that the GCO₂ forms LCO₂. The air exiting shell 67 is atsufficiently low temperature to be used elsewhere in a nearby facility,i.e., the cold air can be used, for example, in an HVAC system or in amore complex configuration to generate more electricity from aturbine-driven GenSet during hot summer months. The air exiting theshell is preferably at sufficiently low temperature to alternatively beused elsewhere in a nearby facility. For example, it can replace thecryogenic device in the PETROGAS fractionation and pressurization devicefor natural gas prior to its further transmission in a pipeline orrefrigeration truck. This process preferably occurs after the LCO₂sequestration has already been completed.

Compressor 62 can be any conventional type such as made by IngersollRand to compress the CO₂ gas 61 to a predetermined pressure, such as 100to 250 psia, which in turn, causes the CO₂ gas to heat up. The heatedand pressurized CO₂ gas 63 is then preferably fed into first heatexchanger 64, which preferably comprises a straight tube, counter-flowtype, with straight tubes 65 supported by tube sheets 71, wherein gas 63can be introduced into tubes 65. Tubes 65 are preferably in a bundle andextended from one end 70, through shell 67 and across baffles 69, suchthat they exit at or near the opposite end 72. In this heat exchanger64, cold water 73 is preferably introduced into shell 67 and circulated,such that the contact between the cold water and outer surface of tubes65 draws heat away from the CO₂ gas passing through the inside of tubes65. Cold water 73 preferably flows into shell 67 at or near end 72 andexits as hot water 75 at or near end 70. This way, it travels in adirection opposite the flow of CO₂ gas 63 through tubes 65, i.e., heatedgas 63 enters at or near end 70 and exits at or near end 72 asrelatively cool CO₂ gas 80. The pressure of CO₂ gas, both at 63 and 80,preferably remains substantially the same, although there is a slightpressure drop due to the passage of the air through tubes 65.

The cooled and pressurized CO₂ gas 80 is then fed into second heatexchanger 66, which, like heat exchanger 64, preferably comprises astraight tube, counter-flow type, with straight tubes 65 supported bytube sheets 71. Tubes 65 are preferably in a bundle and extended from ornear one end 70, and through shell 67 and across baffles 69, such thatthey exit at or near opposite end 72. In this heat exchanger, superchilled air 77 from system 42, rather than cold water, is preferablyintroduced into shell 67 and circulated through the inside of heatexchanger 66, such that the contact between the cold air and the outersurface of tubes 65 helps to draw heat away from the CO₂ gas 80 passingthrough the inside of tubes 65. Super chilled air 77 preferably flowsinto shell 67 at or near end 72 and after heat is exchanged exits aswarm air 79 at or near opposite end 70, such that it travels in adirection opposite the flow of the CO₂ gas 80, which enters tubes 65 ator near end 70 and exits as cryogenic liquid CO₂ 81 at or near end 72.

The temperature of the cold liquid CO₂ 81 that is discharged forpurposes of the present invention is preferably about minus 60 degreesF. or below, although various temperatures are permissible, as will bediscussed. And because there is a phase change from a gas to a liquidwithin tubes 65, and the gas passes through tubes 65, from one end 70 tothe other 72, the pressure of the CO₂ gas within second heat exchanger66 will tend to drop slightly by the time it becomes a cold liquid CO₂.

The cold liquid CO₂ 81 is then preferably fed into cryogenic pump 68which increases the pressure of the cold LCO₂, such as up to 315 ATM, orclose to 5,000 psia, although the actual amount will depend on a numberof factors, as will be discussed. A typical cryogenic pump 68 ispreferably able to deliver the required pressure for the discharged LCO₂82. If one needs 5,000 GPM, it may be necessary to use 25 pumps.However, larger volumetric flow cryogenic pumps can be used.Pressurizing the CO₂ also heats it up, resulting in warmer pressurizedLCO₂. The extent to which the pressure of the liquid CO₂ is increasedmay depend on the depth of the strata, wherein, the deeper the strata,such as close to 5,000 feet deep, the more pressure will be exerted atthe bottom due to the weight of the column of LCO₂ inside the injectionpipe. For example, pump 68 could potentially be used to increase thepressure of the LCO₂ to about 2,600 psig, wherein, the additionalpressure created within the pipe due to the weight of the column of LCO₂above it can contribute to increasing the overall pressure to somewherearound 5,200 psig.

The goal here is to keep the cold LCO₂ cold enough and under enoughpressure to keep the LCO₂ in liquid form, and prevent it from vaporizinginto a gas prematurely when it is injected into the rock formation. Forexample, if the underground rock is warmer than the LCO₂, the pressurewithin the formation may have to be maintained above a certain minimum,or the initial starting temperature of the LCO₂ may have to be colder,to ensure that the LCO₂ remains a liquid as it is being injected intothe pipe. Likewise, if the pressure of the liquid CO₂ within the rockformation drops (because the CO₂ is seeping into the cracks), the LCO₂may have to start out even colder, or the initial pressure may have tobe increased, in order to prevent the liquid from vaporizing prematurelywithin the pipe. For these reasons, the characteristics of eachformation should be taken into account when determining the initialtemperature and pressure of the LCO₂ injected into the pipes. Valves toprevent back pressure from the LCO₂ phase change that may occur in theformation should also be provided.

In this case, the temperature and pressure of the LCO₂ starting outpreferably causes it to maintain its liquid state, as shown in the phasechart of FIG. 7—the temperature and pressure preferably follows left ofthe phase change line 85 and right of line 87. For example, if GCO₂ isreduced to minus 60 degrees F., the pressure will have to be increasedto about 100 psig or more for the gas to change to a liquid. Likewise,if GCO₂ is only about 0 degrees F., the pressure will have to beincreased to about 400 psig or more for the gas to change to a liquid.On the other hand, cooling the GCO₂ down to below minus 100 degrees F.can cause the CO₂ to turn into a solid. The CO₂ will also become a solidat around minus 70 degrees F., provided the pressure is high enough, asshown by line 87.

Adsorption of CO₂ and Desorption of CH₄:

In gas shale, natural gas occurs as a free gas in the intergranular andfracture porosity, but is also adsorbed on clay and kerogen surfaces,very similar to the way methane is stored within coal beds. It has beendemonstrated in gassy coals that CO₂ is preferentially adsorbed,displacing methane at a ratio of two for one or more. Black shalereservoirs react similarly, desorbing methane in the presence ofadsorbing CO₂. If this is the case, black shale serves as an excellentsink for CO₂ and has the added benefit of serving to enhance natural-gasproduction.

Adsorption is the adhesion of atoms, ions, bio-molecules or molecules ofgas, liquid, or dissolved solids to a surface. This process creates afilm of the adsorbate (the molecules or atoms being accumulated) on thesurface of the adsorbent. It differs from absorption, in which a fluidpermeates or is dissolved by a liquid or solid. The term sorptionencompasses both processes, while desorption is the reverse ofadsorption.

Similar to surface tension, adsorption is a consequence of surfaceenergy. In a bulk material, all the bonding requirements (be they ionic,covalent, or metallic) of the constituent atoms of the material arefilled by other atoms in the material. However, atoms on the surface ofthe adsorbent are not wholly surrounded by other adsorbent atoms andtherefore can attract adsorbates.

The adsorption data for carbon dioxide on gas shale and on coal has beencollected over a large range of pressures, but not often at very lowtemperatures. The collected data conforms to the Langmuir Isotherms forgaseous carbon dioxide. The adsorption data at cryogenic temperatureshas been collected at sub-atmospheric pressure so that the CO₂ is stillin the gaseous state (GCO₂). In all cases, the gas adsorption isenhanced as the temperature is reduced or the pressure is increased or acombination of the two. Adsorption of liquids also occurs but is notbased on the theory developed by Langmuir decades ago. Cryogenic liquidadsorbates have been more recently applied to coal adsorbents and shaleadsorbents.

If the underground coal or gas shale is exposed to CO₂ while it isholding the adsorbed natural gas (mostly methane, CH₄), it has a greateraffinity for the CO₂ than the natural gas. Thus, the natural gas isreleased and the CO₂ is adsorbed. This is shown in FIG. 9 which depictsthe coal 100 having a higher adsorption affinity to gaseous CO₂molecules 102 at relatively high pressures (such as 200 to 500 psig ormore) than for gaseous CH₄ molecules 104. In a given coal bed, forexample, as the coal 100 is exposed to CO₂ molecules under pressure,because coal has a greater affinity for the CO₂ molecules than the CH₄molecules, the CH₄ molecules 104 are naturally desorbed, therebyallowing the CO₂ molecules 102 to be adsorbed. This results inadvantageously releasing the CH₄ molecules 104 so that natural gas canbe recovered, while at the same time, adsorbing the CO₂ molecules 102 sothat they can be sequestered in the coal bed. The same process occurs ingas shale.

FIG. 10 shows how the fragmented coal or gas shale fragments or pieces106 are before, during and after the adsorption process. On the lefthand side, before the process begins, a fragment of coal or gas shale106 is shown with CH₄ 108 adsorbed onto its surface, which occurs over aperiod of time within the underground formation. Then, as shown in themiddle drawing, during adsorption, the CO₂ molecules 110 have a greateraffinity for the coal or gas shale fragments 106, and therefore, areadsorbed onto the fragments, while at the same time, the CH₄ molecules108 are desorbed and released as natural gas. After the adsorptionprocess, as shown in the right hand drawing, the adsorbed CO₂ molecules110 remain on the surface of the fragments 106, wherein, the CH₄molecules 108 are released and can be recovered.

The rate at which CO₂ is adsorbed onto and CH₄ is desorbed from thefragments is determined based on the temperature and pressure levels andother factors existing in the formation. In this respect, the firstmathematical fit to an isotherm was likely to have been published byFreundlich and Küister (1894) and is a purely empirical formula forgaseous adsorbates as follows:

$\frac{x}{m} = {kP}^{\frac{1}{n}}$where x is the quantity adsorbed, m is the mass of the adsorbent, P isthe pressure of adsorbate and k and n are empirical constants for eachadsorbent-adsorbate pair at a given temperature. The function has anasymptotic maximum as pressure increases without bound. As thetemperature decreases, the constants k and n change to reflect theempirical observation that the quantity adsorbed rises more quickly sothat higher pressures are not required to saturate the surface.

The Langmuir equation or Langmuir isotherm or Langmuir adsorptionequation or Hill-Langmuir equation relates to the coverage or adsorptionof molecules on a solid surface to gas pressure or concentration of amedium above the solid surface at a fixed temperature. The followingequation was developed by Irving Langmuir in 1916:

$\theta = \frac{\alpha \cdot P}{1 + {\alpha \cdot P}}$where θ or theta is the fractional coverage of the surface, P is the gaspressure or concentration, and α alpha is a constant. The constant α isthe Langmuir adsorption constant and increases with an increase in thebinding energy of adsorption and with a decrease in temperature. Thus,the extent of adsorption depends on physical parameters such astemperature, pressure, concentration in the bulk phase, and the surfacearea of the adsorbent, as well as on chemical parameters such as theelemental nature of the adsorbate and adsorbent. Low temperatures, highpressures, high surface areas, and highly reactive adsorbates oradsorbents generally favor adsorption. Cryo-adsorption is a method usedfor hydrogen storage where gaseous hydrogen at cryogenic temperatures(150-60 K) is physically adsorbed on porous material, mostly activatedcarbon. The achievable storage density is between liquid hydrogen (LH₂)storage systems and compressed hydrogen (CGH₂) storage systems.

One of the objectives of the present method and apparatus is to enablethe coal or gas shale formation to be exposed to CO₂ under the rightconditions within the joints, cracks, fissures and fractures of a rockformation, so that the CO₂ molecules will be adsorbed onto thefragments, whereas, the CH₄ molecules will be desorbed and released,such that the released natural gas can then migrate toward the nearbyrecovery well bores along an imposed pressure gradient and buoy itselfupward through the pipes to the surface. As a consequence, the CO₂ canbe sequestered and stored in the underground formation, and CH₄ can bereleased and recovered.

The proposed approach to injecting LCO₂ into the underground formationis to use an array of injection pipes 120 that extend down through thegeological layers of rock until the targeted coal or gas shale layer isreached, as diagrammatically shown in FIGS. 11, 12 and 13. The injectionpipes, 120, that extend through the underground layers is preferablysolid, whereas, the bottoms of the pipes 133 that extend down throughthe targeted coal or shale strata is preferably perforated.

An example of the various layers of tubing that can be extended into thestrata as part of pipe 120 is shown in FIG. 24. For example, at the top,there can be a conductor casing 103, followed by a surface casing 105,followed by an intermediate casing 107, with concrete 109 formed inbetween each layer, wherein these layers can be provided, depending onthe type and nature of rock formation that is encountered. Layering andusing multiple pipes help to allow the well bores to be safely drilledand the pipes to be safely descended down into the undergroundformation, by preventing unconsolidated materials, such as soil, sandand gravel, from caving in around the pipes during drilling, andallowing various pipes to be isolated relative to the different rocksand layers encountered, which helps to assure that there are no leaks inthe pipe system. The various layers of pipes also act as insulators tohelp maintain the temperature of the surfaces through which the chilledliquid passes. The perforations 119 can then be located at or near thebottom of the pipe, such as in the production casing 111 and/orproduction tubing 113, which is preferably the smallest pipe within thelayers, and preferably extends down within the coal or gas shale strata,which can be below layers of rock and mud. Perforations 119 arepreferably substantially horizontal such that from a substantiallyvertically oriented injection pipe 120, the LCO₂ can be releasedsubstantially horizontally into the matrix.

The injection pipe 120 is preferably made of steel or other strongmaterial and can be circular and of sufficient internal diameter andthickness depending on the length and pressures that are expected to beencountered. It can be much like the pipe shown in FIG. 24. Theperforations 119 can be circular and of sufficient size to enable asufficient flow of fluid into and out of the targeted rock formation,such as a gas bearing rock layer as shown in FIG. 24. For example, fourperforations can be formed in the shape of a ring at a predeterminedheight along the length of the pipe. In this respect, the first ring ofholes can be located close to the top of the targeted production layeror strata, such as about fifteen feet below the upper surface of thelayer. Then, additional rings of holes can be extended down along thepipe 120, such as about once every fifteen feet or so, until the lastring of holes can be located at the bottom of the well bore.

The total cross sectional flow area of the perforations 119 ispreferably designed to match the cross sectional flow area of the pipeitself. Thus, the design of each pipe will depend on the internaldiameter of the pipe, the height or thickness of the rock formation itis being used to fracture, and the size or diameter of each perforationin the pipe. For example, consider a 250 feet vertically thick shaleformation where the internal diameter of the pipe is eight inches, andthe perforations are one inch in diameter (four perforations at eachlevel). In such case, the optimal design might be 16 rings of four holeseach (around the circumference), where the top ring will be 7 feet fromthe nearest layer interface, and each intermediate ring will be 14.7feet apart from the other. Also consider a 50 feet vertically thickshale formation with the same internal diameter of pipe, and the samediameter perforations, wherein, in such case, the optimal design mightbe 16 rings of four holes each, where the top ring will be 1.5 feet fromthe nearest interface, and each intermediate ring will only be 3 feetapart. This allows for the maximum rate of flow through the perforationsgiven the size and diameter of the pipe. If more perforations areprovided around each ring, then the vertical spacing of the rings willhave to be increased. Each pipe can be designed to accommodate theconditions that exist in each application.

To allow for proper recovery and release of gases that are producedwithin the formation, similar arrays of recovery pipes 122 that extenddown into the same geological layers are preferably provided. Similar tothe injection pipes 120, the upper portion of the recovery pipes 122 arepreferably solid with various layers of pipes and concrete, wherein thebottoms of the pipes that extend down into the targeted formation ispreferably perforated 119. These recovery pipes 122 can be substantiallysimilar to the injection pipes 120, i.e., they can be made of steel orother strong material and can be circular and of sufficient diameter andthickness depending on the length and pressures that are expected. Theperforations 119 can also be circular and of sufficient size and numberto enable a sufficient flow of fluid into the pipe from the rockformation.

FIG. 25 shows an embodiment of an injection pipe 201 that extends downthrough underground substrate 206 and into a stratum 202 having an innerpipe 203 and outer pipe 205 concentrically oriented in connection witheach other. Inner pipe 203 is preferably shorter than outer pipe 205 andends substantially before the bottom of outer pipe 205 within stratum202, although not necessarily so, as shown in FIG. 24. Multipleperforations 207 are preferably provided on or near a bottom section 214of outer pipe 205 within stratum 202, such that pressurized LCO₂ can bereleased through perforations 207 and into stratum 202, as discussed.This is different from the embodiment of FIG. 24 where the perforationsare on the smallest inner pipe. Preferably valves 209, 211 are providedat or near the bottom of inner and outer pipe 203, 205 which are capableof sealing the openings therein, including the concentric space betweeninner pipe 203 and outer pipe 205. For example, space 210 within innerpipe 203 can be sealed with valve 209, and space 212 between inner pipe203 and outer pipe 205 can be sealed with valve 211. Valves 209, 211preferably help to seal the bottom openings in inner and outer pipes203, 205 such that pressure inside space 210 and/or space 212 can buildup within injection pipe 201 at the desired time. Valves 209, 211 alsoenable water and other substances found within stratum 202 from beingsucked back into spaces 210 and 212, via perforations 207, and upthrough injection pipe 201 toward surface 200. Preferably, bottom distalend 218 of outer pipe 205 is sealed.

Within a given application, one injection pipe 201 is preferably locatedat the center of a number of recovery pipes 221 which fills theavailable acreage above the targeted formation. Like injection pipe 201,each recovery pipe 221 preferably consists of an inner pipe 223surrounded concentrically by an outer pipe 225, wherein the inner pipe223 is shorter than the outer pipe 225, as shown in FIG. 27, althoughrecovery pipe 221 can be more like the pipe shown in FIG. 24. Recoverypipe 221 also preferably has multiple perforations 207 at the bottomextended down into matrix 202. A valve 231 is preferably provided at thebottom of inner pipe 223 to seal space 230 within inner pipe 223. Anadditional valve 233 is preferably provided to seal space 232 betweeninner pipe 223 and outer pipe 225. In this respect, preferably, usingthe valves, the bottom of each injection and recovery pipe 201, 221 canbe opened and closed during the pressurized injection cycles. Recoverypipe 221 preferably enables methane and other natural gases to rise andbe extracted and recovered from the matrix.

Preferably, there are several recovery pipes 122, 221 for each injectionpipe 120, 201, within a particular geographical area, such asconcentrically surrounding the injection pipes 120, 201, as shown inFIGS. 15 and 16. That is, for every injection pipe 120, 201, there arepreferably several recovery pipes 122, 221, such as four to eight, ormore, in the form of a grid to enable a sufficient amount of gas ormethane to be recovered from the formation that surrounds a singleinjection pipe 120, 201. Because the goal is to release the lowerdensity natural gases and recover them from a large geographical area,there are preferably more recovery pipes 122, 221 than injection pipes120, 201. Each recovery pipe 122, 221 is preferably extended deeper intothe strata than the injection pipes 120, 201, as shown in FIGS. 17 to19, which enables gases formed within the fractures that are formed inthe deeper areas that are below the injection pipes 120, 201 to bereadily recovered.

Preferably, injection pipes 120, 201, are spaced apart a sufficientdistance relative to each other to enable the natural gases formedwithin the geographical area to be efficiently recovered. This can bebased, for example, on the expected reach of the fracturing method,wherein the greater the reach, the greater the distance that can beextended between adjacent injection pipes 120, 201. Because thefracturing method can effectively reach great distances, the number ofinjection pipes 120, 201 within the same geographical area can bereduced. For example, in one embodiment, the distance between injectionpipes 120, 201 and the surrounding recovery pipes 122, 221, as shown inFIG. 15, can be about 1,000 feet or more, and thus, the distance betweenadjacent injection pipes 120, 201 can be greater, such as every 2,000feet or more. Relative to one injection pipe 120, 201, the surroundingrecovery pipes 122, 221 are preferably used as receivers for gasrecovery, wherein this layout can continue throughout the acreage, withno interference between adjacent sets of injection 120, 201 and recovery122, 221 pipes.

FIG. 15 shows an example of an array of pipes that can be used on thesurface of a geological formation, wherein injection pipes 120, 201 andrecovery pipes 122, 221 are laid out in grid fashion, with the narrowvoid or fracture areas created by the high pressure injection jets ofLCO₂ emanating from the injection pipes 120, shown by the fan-shapedconfiguration 123. It should be noted that because the perforationstypically comprise four to eight holes spaced equidistance apart at 45to 90 degrees at a predetermined level or height, each void or fracture123 formed by each perforation will often form a pattern of voids 123that are at angles relative to each other. Where there are moreperforations, such as eight or more, there will be more voids 123.

FIG. 15 also shows a preferred pattern for rubblization by orienting theperforation holes on the injection pipes 120, 201 so that the voids 123they create will mesh with each other. As shown in FIG. 15, one row orgrid 125 of injection pipes 120, 201 is oriented with perforations (andtherefore voids 123) at forty-five degrees relative to the grid pattern,wherein, the adjacent row or grid 127 is oriented with the perforations(and voids 123) extending ninety degrees relative to the grid pattern,wherein the perforations on one row 125 are at forty-five degreesrelative to those of the adjacent row 127. The same is true betweengrids 127 and 129. This way, by aiming the injection in differentdirections, to create voids 123 extending at different angles, bettercoverage is possible using fewer injection pipes 120, 201. It can alsobe seen that more direct pressure can be applied in the direction ofvoids 123, whereas, less direct pressure is applied between the voids123, and therefore, as shown in grids 125 and 129, it may be desirableto orient the perforations to direct the LCO₂ injections toward thefurthest-away recovery pipes 122, 221.

FIG. 11 shows the present method used in an abandoned coal mine, whereininjection pipes 120 are positioned within soil 128 and down into anabandoned tunnel 124 where there are layers of coal 126. As can be seen,when the LCO₂ is injected into injection pipes 120, and released throughperforations, the LCO₂ is injected into the tunnel 124 where the CO₂ canbe adsorbed onto the coal surfaces, and CH₄ can be desorbed and releasedinto tunnel 124. Pressure is preferably allowed to build by sealingrecovery pipes 122, wherein the relatively high pressure and lowtemperature within the matrix can help cause the CO₂ to be adsorbed andthe CH₄ to be desorbed, such that natural gas can be recovered throughrecovery pipes 122. In addition to recovery pipes 122, which can beopened for gas recovery, injection pipes 120 can also be opened once theinjection has stopped, to allow for increased gas recovery. Injectionpipes 120 can also remain closed at the bottom while the LCO₂ is beingintroduced, such that when the pressure has built up, the LCO₂ can bereleased to drive the LCO₂ directly into the coal stratum.

FIG. 12 shows the present method using injection pipes 120 positionedwithin soil 128 and down into an underground coal or gas shale stratum130 where there are layers of coal or gas shale present. When the LCO₂is injected into pipes 120, and released through perforations 207 at 133under pressure, the coal or shale will begin to break up and formfractures therein, i.e., it will become rubblized, wherein long narrowpassages can be created within the formation to increase itspermeability, as shown in FIGS. 17 to 19. The broken fragments 132created by this process then become more susceptible to adsorption ofGCO₂ and desorption of CH₄. At this point, the recovery pipes 122 arepreferably closed at the top, as shown in FIG. 17, to allow the pressureinside the formation to build up. Once the injection is stopped,injection pipes 120 are also preferably closed at the top, as shown inFIG. 18, such that the pressure within the stratum can be maintained ata predetermined amount, while adsorption and desorption continue.

FIG. 13 shows a similar method and apparatus using injection pipes 120positioned within soil 128 and down into an underground coal or gasshale stratum 130, but in this case, injection pipes 120 have a benthorizontal portion 134 which is directed laterally within the targetedformation. When the LCO₂ is injected into pipes 120 (with the recoverypipes 122 closed) and released through the perforations, the LCO₂ willbe injected through the horizontal pipe 134, and into the stratum,thereby causing the coal or shale to break up in various directions,i.e., again, it will become rubblized to increase the permeability ofthe formation. The broken fragments 132 created by this process are madesusceptible to adsorption of CO₂ and desorption of CH₄. Once theinjection is stopped, injection pipes 120 are preferably closed, suchthat the pressure within the stratum can be maintained.

When the targeted rock formation is a relatively thin strata,horizontally orienting the bottom portion 134 of injection pipe 120 andextending it horizontally through the formation as shown in FIG. 13 canenhance its ability to reach and fracture the formation. The horizontalportion 134 in such case is preferably provided with perforations thatextend in various directions to allow the LCO₂ to be released andinjected into the targeted rock formation radially outward. The distancethat the horizontal portion 134 extends into the formation can be basedon the nature and size of the targeted strata. For example, horizontalportion 134 can be extended about half or more of the distance from theinjection pipe 120 to the nearest recovery pipe 122. Thus, if thedistance to the nearest recovery pipe is 1,000 feet, the horizontalportion can be extended about 500 feet or more.

It should be noted that the amount of LCO₂ injected into layer 130 isbased on the adsorption capacity of the zone around each injection pipe120, and the thickness, density and hardness of the coal or shale layer130, etc. Thus, after an appropriate amount of LCO₂ has been injectedinto the injection pipe 120, the valve is preferably opened (the valvesof the surrounding recovery pipes 122 were closed previously). Byforcing the high pressure liquid CO₂ into a shale or coal bed stratumvia a pre-chilled vertical pipe with an end extension of perforations,the high pressure (>4,660 psia) liquid LCO₂ can be injected through eachof the circular perforations in the pipe and create fractures forming along cavity of small diameter (pencil-like) openings or voids 123 in allradial directions extending from the perforated pipe. The high pressureliquid CO₂ is preferably forced through each perforated hole andpenetrates the shale or coal bed stratum, wherein, when the pressureexceeds the fracture strength of the rock formation, fractures arecreated in the rock.

The factors used to determine the formation fracturing pressure are afunction of well depth in units of psi/ft. For example, a fracturegradient of F=0.823 psi/ft. in a well with a true vertical depth of1,000 feet would predict a total fracturing pressure of 823 psi. At5,000 feet depth, on the other hand, it would predict a fracturepressure of 4,115 psi (based on 5,000×0.823 psi/ft.). When the LCO₂ isdelivered to the stratum at pressures above the stratum's fracturestrength, the pressure is able to fracture and break up the rockformation, wherein the pressurized LCO₂ can produce long pencil-likefractures and additional openings that radiate from the main fracture.The LCO₂ then fills not only the main fracture but also the radiatingvoids.

The goal of this process is to create narrow fractures and fissures inthe rock formations, such as those shown in FIGS. 17 to 19, whichincreases the formation's permeability. This allows more of the coaland/or gas shale fragments to be exposed to CO₂, such that moreadsorption can take place, throughout a greater area within thegeographic site, which means that more CO₂ can be sequestered, andgreater amounts of natural gas can be desorbed, released and recovered.

FIG. 14 shows the web-like pattern of fractures in plan view that can becreated by the present fracturing method. In particular, it shows afour-hole perforation configuration which can disperse the LCO₂ underpressure in four different directions to create a series of fracturevoids 123, as well as a web-like pattern of fractures 137 extending indifferent directions. Even if the perforations are annularly located infour specific locations, and the LCO₂ is released as a jet streamthrough each of those perforations, i.e., corresponding to the voids123, the pressure gradient created by releasing the LCO₂ under pressurecan cause the surrounding areas to break up as well. The violentexpansion of the LCO₂ to GCO₂ that occurs, as will be discussed, alsohelps to break up the formation in all directions. Thus, while FIG. 14shows the four jet streams created by the pressurized LCO₂ injected intothe formation, it also shows the long pencil-like horizontal openings123 that are formed thereby, as well as the spreading of the surroundingcracks that are widened by the newly created field of stress. The lengthof the high stress field that is formed can extend to 2,500 feet or morein length.

FIG. 17 shows an initial phase wherein the recovery pipes 122 are closedat the top 154, whereas, the injection pipes 120 are open 156 to allowthe LCO₂ to be injected into the rock formation 160. As can be seen, afracture void 123 is preferably created in the direction of eachperforation 162, wherein a web-like pattern of fractures 137 can becreated that extends beyond each void 123. In particular, FIG. 17 showshow each perforation can disperse the LCO₂ under pressure in ahorizontal direction to create a series of horizontally orientedfracture voids 123, while at the same time, the pressure gradientcreated by releasing the LCO₂ can cause the surrounding areas to breakup and create a web-like pattern of fractures 137 extending in differentdirections.

FIG. 18 is similar to FIG. 17, but shows the next phase wherein both theinjection pipes 120 and recovery pipes 122 are closed at the top 154,wherein, the pressure within the formation 160 can be maintained. Again,as can be seen, a fracture void 123 is preferably created in thedirection of each perforation 162 as the pressure jet is released, butas the injection is stopped, and the pressure is maintained within theformation, the web-like pattern of fractures 137 can continue to beextended in different directions. This preferably continues for apredetermined amount of time, as the LCO₂ and GCO₂ is adsorbed, and theCH₄ is desorbed and released.

At some point, there can be a dramatic phase change within the formation160, which can explosively cause the LCO₂ to transition into a gas,wherein its expansion can cause greater fracturing along the joints andfractures. This can further increase the size of the fractures 137extending through the formation, thereby increasing its permeability.

FIG. 19 is similar to FIGS. 17 and 18, but shows the next phase whereinall the pipes 120 and 122 are opened to allow the CH₄ gas to berecovered at the surface. Preferably, the pressure is released slowly,or gradually, such that the pressure within the formation can bemaintained for a predetermined period of time. That way, not only maythe fracture voids 123 continue to form additional web-like patterns offractures 137 within the formation, but more importantly, the GCO₂ willcontinue to be adsorbed, and the CH₄ will continue to be desorbed, suchthat a greater amount of CO₂ can be stored, and a greater amount ofnatural gas can be released and recovered.

FIG. 19 represents the time period after two weeks where it may be safeto recover the natural gas that has buoyed itself up toward the surface.In this respect, it is desired to open the natural gas relief valvesslowly, i.e., to a small orifice area, to ensure that the pressurewithin the formation is still maintained in the production layers afterthe injection has stopped, and so that fracturing can continue and moreGCO₂ can be adsorbed, and CH₄ can be desorbed.

It is also expected that the relief of gas pressure will cause thefractured openings and voids to close in, which in turn, will trap someof the LCO₂ or GCO₂ that has yet to be adsorbed, and the natural gasthat has been desorbed but has yet to migrate to the recovery pipes. Thetiming of the valve opening thus preferably coincides with the recoveryof the natural gas so that most of the CO₂ will have been adsorbed andmost of the natural gas will have been recovered by the time the valvesare opened and pressure is released.

As shown in FIGS. 17, 18 and 19, even though the rings of perforationsare spaced vertically apart, and the LCO₂ is released only at the levelswhere the horizontal voids 123 are shown, by releasing the LCO₂ undersufficient pressure, the surrounding areas of rock, both above and belowthe perforations, are fractured and broken up, i.e., within a certainperimeter extending above and below each ring. Thus, a greatergeographical area can be reached and fractured by using a singleinjection pipe 120, wherein the fractures can reach as far as 1,000 feetor more, but also extended above and below each void 123 by severalfeet, such that more CO₂ can be stored, and more natural gas can bereleased and recovered from the site.

Note that the fracture zone may only contain fractures that are about ½inch in height, width or diameter, but nevertheless, the overall zonemay extend horizontally to 2,500 feet or more in length parallel to thebottom and top surfaces of the layer and several feet above and belowthe void 123. The pressurized liquid not only forms a long cavity ofsmall diameter (0.5 inch to 1 inch), but also causes fracturing toradiate all around the circumference from the horizontal cavity.

At these high pressures (>4,000 psi) and low temperatures the liquid CO₂exchanges place through adsorption with the natural gas (CH₄) at eachexposed site of the gas shale or coal particle surface. The highpressure cryogenic pump 68 at the surface continues to apply pressure tocontinue the fracturing process while the injection pipe 120 is open.When the cryogenic pump 68 is stopped and all valves are closed shut,fracturing will continue and the pressure in the liquids starts todecrease because of the continuous opening of additional fracturevolumes. At these pressures and temperatures, however, the closed valvesfacilitate desorption of the natural gas (CH₄) and simultaneousadsorption of the CO₂ which continues for an extended period of time.

Preferred Pressure Cycling Method:

The preferred method involves using the above described processes torepeatedly inject the cold liquid CO₂ into the coal or shale matrix, butby increasing and decreasing the pressure of the liquid CO₂ injectedinto the formation, and therefore, the pressure within the matrix, aswell as maintaining a substantially low temperature within the matrix,by regulating the temperature of the injection pipe and LCO₂ injection,which can enhance the ability of the CO₂ to be adsorbed and for CH₄ tobe desorbed and released. The method preferably involves initiallyreleasing the LCO₂ into the stratum under high pressure, such aspreferably above the fracture gradient of the matrix, which helps breakup the matrix to form fractures therein, and then, after a predeterminedperiod of time, closing the injection pipe, which allows the pressurewithin the matrix to drop, which advantageously allows additional cleatsto form within the stratum, and more CO₂ to be adsorbed and CH₄ to bedesorbed. Meanwhile, the LCO₂ is allowed to warm up once it enters intothe matrix, due to the higher temperatures that exist within the stratumat that level, such that it changes phase explosively from a liquid to agas, wherein the force of expansion helps to further break up thematrix. Then, after the passage of sufficient time, which allows thepressure to drop back down, more CO₂ can be adsorbed and more CH₄ can bereleased, as these steps are repeated.

The orientation of the pipes preferably involves using an injection wellbore located in the middle of a number of recovery well bores, such asat corners of a square, although any configuration that achieves thedesired results is possible. This 5-Point field entity can then berepeated in all directions until the available acreage above theformation is filled. A 9-Point field entity as shown in FIG. 15 or otherconfiguration can also be used.

In this case, each well bore can be configured as shown in FIG. 24, withmultiple layers, or as shown in FIGS. 25 to 27, wherein each injectionpipe 201 consists of inner pipe 203 surrounded by outer pipe 205 withperforations 207 located at the bottom extended into the matrix, asshown in FIG. 25, and wherein each recovery pipe 221 consists of innerpipe 223 surrounded by outer pipe 225 with perforations 207 located atthe bottom, as shown in FIG. 27. One or more valves, 209, 211, 231, 233,are preferably located at the bottom of each injection and recovery pipewhich can be opened and closed during the pressurization and injectioncycles, as will be discussed.

The well bores preferably have three operational modes. In the firstmode they can be used to dewater the underground formation in its nearbycontact area while the valves at the bottom of the well bores areopened, which is often necessary due to the existence of a significantamount of water below the water table. This can be accomplished, forexample, by using one pump 243 located at the top of the well bore, andanother pump 245 located at the bottom, as shown in FIG. 27, wherein along rod 241 can be extended into the inner pipe 223, such that thepumps can be operated and used to force water up through the well bore.

It can be seen that water can be pumped up through inner pipe 223, usingpumps 243, 245, with valve 231 open and valve 233 closed, wherein watercan be extracted from the top 247 of well bore 221. Or, by reversing theflow of water using pumps 243, 245 down through inner pipe 223, andopening both valves 231, 233, a mixture of water and methane can bepumped up through space 232 between inner pipe 223 and outer pipe 225,wherein the mixture can then be extracted from the top 249 of well bore221. The water/methane mixture at the top can then be introduced into aseparator 251 which enables the methane to rise above the water and berecovered and distributed using a compressor 253, wherein the water atthe bottom of separator 251 can also be removed.

The initial step of dewatering is helpful when the targeted rockformations are saturated or otherwise filled with water, such as fromnearby water aquifers, which will otherwise interfere with the pressurecycling methods of the present invention. To remove water from theunderground formation, a pump at the top and/or bottom of each well bore(both injection and recovery pipes) can be used to draw water out. Afterthe well bores have been pumped clear of water (such as over severalmonths), methane may appear at the top of the well bores, such as viathe annulus between the inner and outer pipes, wherein the pumping outof water strongly reduces the local pressure within the matrix near thewell bores, but only weakly reduces the pressure in the matrix furtheraway from the well bores. This reduction in pressure creates a pressuregradient which causes the methane to desorb and migrate toward the wellbores, wherein water and methane that appear at the top of the holes canbe processed and the methane collected or burned off. When thedewatering is completed, the water pumps are preferably turned off. Thesame process can be used for both recovery and injection well bores.

Second, when the injection well bores have been dewatered, the next steppreferably involves using liquid nitrogen and/or super cold gaseousnitrogen to pre-chill the injection pipes. It is normally desirable toinject a predetermined amount of liquid nitrogen into the injectionpipes first, which helps to pre-chill the pipes, so that when the LCO₂is injected, the pipe will be cold enough to avoid disadvantageouslycausing the LCO₂ to warm up and change phase to a gas prematurely. Forexample, injection pipes 120, 201 can be chilled with liquid nitrogen(such as at minus 321° F.) until the pipe attains a steady-statetemperature of about minus 60° F. or less, i.e., via inner pipe 203,while the valve 209 at the bottom can remains closed. During this time,a change of phase may occur, turning the liquid nitrogen into coldgaseous nitrogen, until the desired temperature is obtained. Note space212 in the annulus around inner pipe 203 along the length of inner pipe203 and outer pipe 205 can serve to interrupt the radially inward heattransfer flow.

Because it is important for the temperature inside the pipe to remainsubstantially low, and because there will be heat transferred from thesurrounding soil and rock to the LCO₂, a thermocouple (not shown) ispreferably attached to the pipe at a predetermined depth to show whenthe injection pipe reaches a certain temperature and therefore is readyto accept the pressurized LCO₂ without flashing to GCO₂. It can be seenthat the liquid nitrogen may continuously flash off to nitrogen vaporand vent upwards from the pipe to the surface during this process. Thus,it will be helpful to use the thermocouple to determine when theappropriate temperature has been reached and when the inflow of liquidnitrogen is completed.

Third, while the pipes are being pre-chilled in the manner describedabove, the cryogenic pump is preferably turned off, and the vent at thetop of the injection pipe is preferably opened, while the bottom valveis preferably closed. This produces zero pressure within the injectionpipe to start with. The steps involved over a period of time aredesignated as events T1 through T10 as shown in FIGS. 33 to 44 inconnection with injection pipe 301, pump 303, top vent 305 and bottomvalve 307. Although these figures refer to injection pipe 301, it shouldbe noted that the same process can be used in connection with the otherpipes, such as 120 and 201.

According to event T1, as shown in FIG. 33, which is prior to theoperation of the process, pump 303 is turned off, top vent 305 is openand bottom valve 307 is closed. Then, after injection pipe 301 ischilled in the manner described above, pump 303 is preferably turned on,but set to low power, as shown in FIG. 34, and liquid CO₂ is preferablyintroduced gradually into injection pipe 301 while initially keepingbottom valve 307 closed.

The cold liquid CO₂ can also be delivered using the apparatus shown inFIG. 26. FIG. 26 shows a storage tank 261 for storing cold liquid CO₂under pressure, such as at about 350 psig with a temperature of aboutminus 20° F. These amounts are for exemplary purposes only and by nomeans intended to be limiting. At the same time, a nearby storage tank265 for storing liquid nitrogen can be provided, such as liquid nitrogenat 30 psig with a temperature of minus 320° F. A heat exchanger 263 canthen be provided that communicates with both tanks 261, 265, wherein theliquid nitrogen can be used via heat exchanger 263 to reduce thetemperature of the LCO₂ further. When the system is ready for the LCO₂to be injected into the well bore, the LCO₂ can be reduced to atemperature of minus 60° F. using heat exchanger 263, and then, the LCO₂can be introduced into injection pipe 201.

Initially, each injection pipe 301 is preferably gravity-filled withLCO₂ without using pump 303, or with pump 303 set to low pressure, asshown in FIG. 35. At this point, the bottom valve 307 is preferablyclosed, but vent 305 at the top is open. This is because as the pipe 301is being filled with LCO₂, gas bubbles will start coming up to thesurface, indicating that liquid CO₂ is still changing phase, whichindicates the pipe is still not cold enough. Then, when the GCO₂ bubblesstop coming to the surface, indicating that pipe 301 has reached asteady state temperature, and is ready for the introduction ofpressurized LCO₂, pump 303 is preferably turned on to full power tobegin pressurizing pipe 301 with LCO₂, as shown in FIG. 36. At thispoint, top vent 305 and bottom valve 307 are both preferably closed, toensure that pressure inside pipe 301 can be increased.

Cryogenic pump 267 can be used to further increase the pressure of theLCO₂ as necessary. The operative pressure that can be released from thebottom of pipe 301 preferably takes into account the hydrostatic headpressure created inside the well bore due to the weight of the LCO₂column inside injection pipe 301. For example, with a sufficient amountof LCO₂ inside injection pipe 301, such as to 5,000 feet below thesurface, the weight of the LCO₂ column inside can create additionalhydrostatic pressure, thus making it unnecessary to introduce the LCO₂at the full rated 5,000 psig pressure. Instead, the LCO₂ can beintroduced at a lower rate, such as 2,500 psig, by taking into accountthe additional hydrostatic pressure exerted at the bottom of the pipe bythe weight of the LCO₂ column inside the pipe. For example, when thedepth of the matrix is 5,000 feet, the LCO₂ within the pipe can create atotal head pressure of about 2,500 psig, which means that to achieve atotal pressure of 5,000 psig at the bottom of the pipe, the pump willonly have to provide a pressure of 2,500 psig, since, the additionalpressure will be provided by the head pressure of the LCO₂ in the pipe.For this reason, it is possible to use, for example, a 2,600 psig ratedcryogenic pump even if the desired pressure within the pipe is 5,000psig, since the weight of the liquid CO₂ column inside the pipe can helpincrease the pressure, i.e., the liquid CO₂ column can increase thepressure from 2,600 psig to 5,000 psig or more.

Then, at the appropriate time, with the injection pipe filled with LCO₂,which can raise the pressure at the bottom of the pipe to 5,000 psig,the bottom valve 307 is preferably opened and the pressurized liquid CO₂is preferably allowed to flow through the perforations and into the rockformation. The injected liquid CO₂ pressure is preferably far above thefracture strength of the matrix so that the pressure can break up therock formation and create cavities and openings and fill them withpressurized liquid CO₂ (at 5,000 psig) within the matrix. The highstresses that exist preferably create rubblized rock around the cavity,and fractures surrounding the solid matrix bed. Another consideration ismaking sure the pressure is sufficient despite the friction created bythe walls of the pipe as the LCO₂ travels through the pipe when the LCO₂is being released. And because the fracture gradient of the matrix isdependent on the depth of the matrix, it will be important to ensurethat the pressure is sufficient to crush and break up the rock formationand create fractures in the matrix at that depth.

Preferably, at this point, the top vent is closed, to ensure that thepressurized LCO₂ is released at the bottom, rather than at the top,while the pump remains on. In this respect, it should be noted that whenbottom valve 307 is opened with a certain pressure inside the injectionpipe 301, the pressurized LCO₂ will be released through the perforationsat a high velocity, such as 400 to 500 ft./sec. or more, which is basedon the total pressure that exists inside the pipe 301, and the size andnumber of the small perforations through which the LCO₂ under pressureis allowed to pass, wherein the speed of flow is determined by theconservation of mass between them. As such, preferably, the pressurewill drive a jet stream of LCO₂ into the matrix with a pressure greaterthan the fracture strength of the rock formation, wherein the length ofpenetration of the LCO₂ is determined by the pressure formed at thedistal end of the proliferation, until it is no longer able to perforatethe matrix.

The pressure is preferably maintained in the liquid CO₂ for a durationthat is designed to create fractures and the craters extended radiallyoutward toward the recovery well bores but not completely reach therecovery well bores. Eventually, once it is determined that thefracturing of the impact zone has been completed, the bottom valve ispreferably closed, until no more liquid CO₂ is injected into the cavityand the pressure in the matrix eventually decays. It is important thatthe valve be closed slowly so that the damaging effects of a waterhammer can be avoided. At that point, along with closing the bottomvalve, the pump is preferably turned off, and the top vent is preferablyopened, and the pressure inside the pipe is released.

During this time, the liquid CO₂ that has been introduced into thematrix will continue to proliferate into the cavity and form fractures,thereby helping to further break up the matrix, which also contributesto a decline in pressure, as the volume of space within the matrixexpands. This also encourages the adsorption of CO₂ into the formationand desorption of CH₄, i.e., the CO₂ filling up the space will begin toadsorb into the formation and CH₄ will be desorbed. Eventually, with thebottom valve 307 closed, the relatively high temperature of the rockformation will eventually cause the extremely cold temperature of theliquid CO₂ to increase to the point where the LCO₂ will change phaseexplosively to GCO₂, which can occur when the pressure within the matrixdrops down, such as to 400 psig. This causes the liquid CO₂ to flash andexpand, to form GCO₂ which further helps to break up the matrix, andfurther expand the cavity and crush zones. With the bottom valve closed,the extra pressure created by this phase change can be up to 20,000 psigor more, which significantly enhances the break up and rubblization ofthe matrix, and then eventually, as the fractures and cracks continue toexpand and grow, the pressure within the matrix will drop back downagain over time.

This increase in cleats within the matrix increases the matrix'spermeability and causes the same mass of gas to fill a larger volume.This induces reduced pressure. The lower pressures will facilitate theadsorption of CO₂ and desorption of CH₄ in the substrate. While highpressure damages and fractures the matrix to allow the cleats to open upand expand, the reduction in pressure permits enhanced adsorption of CO₂and desorption of CH₄. The increased permeability also causes thediffusion process to be accelerated. This is shown in FIG. 31, where thebottom row shows the extent of permeability achieved through one cycleunder high pressure, and the second row shows how reducing the pressureactually enhances permeability. Then, the third row shows the effect ofrepeating the cycle under high pressure again. This indicates that aminimum of two cycles will be advantageous, and while additional cyclesare contemplated, the chart indicates that performing more than twocycles may not always produce results commensurate with the number ofattempts made. At the same time, the rubblization effect of repeatedexposure of the matrix to high pressure jet streams will enhance thefracturing of the matrix, which makes the coal or shale surfaces moreaccessible.

At this point, it is worth noting that the methane in the matrix, and inparticular, near the injection well bore will continue to be releasedand pushed out toward the recovery well bores, and then, over time, acloud of gaseous CO₂ will begin to form around the injection area,wherein, the outer surface of the CO₂ cloud, which includes a mixture ofCO₂ and methane, will move further toward the recovery well bores,wherein at the outside of the cloud there will remain a significantamount of methane that has not been swept up. In this respect, it can beseen that it will be helpful to monitor the pressure of the CO₂ cloudnear the injection well bore, such as from 20,000 psig down to 5,000psig, and then down to about 500 psig, and then, ultimately down to 200psig, so that a sufficient amount of pressure can maintain a pressuregradient that will cause the released methane to continue to migratetoward the lower pressure areas near the recovery well bores. And, byallowing the pressure to drop down to 200 psig or less, this will helpto enhance the ability of the CO₂ to be adsorbed into the formation andCH₄ to be desorbed and released.

To repeat the cycle, the pump can be turned back on and pressure withinthe injection pipe 301 can be increased again. Then, when sufficientpressure has built up inside the injection pipe 301, and at theappropriate time, such as when the pressure within the matrix near theinjection pipe has dropped to below 200 psig, the bottom valve 307 canbe opened again and pressurized LCO₂ can be released back into thematrix, wherein the matrix can be exposed to the high pressure liquidCO₂, thereby enabling continued compression crushing and fracturing toovercome the induced hoop stresses within the matrix. Because the secondtime around, there will already be cavities and openings formed withinthe matrix from the first pressurized flow of LCO₂, the high pressureLCO₂ will cause a longer and more sustained jet stream to be extendedinto the formation, which can reach the distal end of the cavity,thereby extending the crush zone further away from the injection wellbores and toward the recovery well bores. Then, at the appropriate time,the bottom valve 307 can be closed again, wherein the pressure in thematrix can be allowed to drop and the temperature of the LCO₂ can beallowed to warm, and then, the liquid CO₂ will be allowed to flashexplosively into gaseous CO₂ again and further penetrate into the moredistal portions of the coal matrix. Then, as the LCO₂ changes phase to agaseous CO₂, the further-away areas of the matrix will expand further,causing more CO₂ to proliferate into the formation, and extending thereach of the adsorption. Accordingly, the CO₂ will also spreadthroughout the crush zone and into the distal ends of the cavity,wherein the CO₂ will expand along the perforation length and alsoradially outward. This additional injection extends the fracture zoneahead of the CO₂ cloud and mixture of CO₂ and CH₄, and will continue tobreak up additional areas toward the recovery pipes.

This cycle can be repeated multiple times, such as over the course of amultiple year period, to further break up the coal formation and furtherenhance the ability of the coal or shale to release methane gas. Thisway, more of the matrix can be exposed to the CO₂ due to higherpermeability, which in turn, enables greater adsorption of CO₂ anddesorption of methane.

This induced pressure cycling preferably forms cleats and momentarilycompresses the cleat spaces, but then relieves the cleats when thepressure is reduced, thereby allowing them to expand. This pressurecycling has the advantage of using relatively high pressure to fracturethe matrix to create new cleats and the advantage of using low pressureto allow the cleats to expand and enhance adsorption of CO₂ anddesorption of CH₄.

The cold temperature of the CO₂ (preferably kept to below +10° F.) alsoenhances the rate at which the CO₂ is adsorbed onto the exposed surfacesthat simultaneously displaces the CH₄ into the volume within the cleatsand pores. In this respect, FIG. 28 shows that the degree to whichmolecular adsorption and desorption is exchanged within the coal matrixis more efficient at lower temperatures, wherein adsorption/desorptionbecomes accelerated thereby. Note that a CO₂ molecule will adsorb onto acoal surface more than twice as effectively when the temperature isminus 20° than when the temperature is at plus 180° F. And given thelithostatic temperatures that exist underground at various depths, itcan be seen that a matrix located at a depth of 7,000 feet undergroundwill normally be at a temperature of about 180° F., i.e., the groundtemperature normally ranges from an average temperature of about 70° F.at ground level to about 100° F. at a depth of 2,000 feet to about 150°F. at a depth of 5,000 feet. Thus, depending on the depth of the matrix,and the existing temperatures found underground, the system will have tobe adapted to ensure that the LCO₂ injected into the stratum will bereleased at the appropriate temperature, i.e., preferably below plus 10°F.

FIGS. 29 and 30 show how the pressure in the injection pipe and in thematrix shift up and down as the pressure of the LCO₂ is increased anddecreased, which coincides with the opening and closing of the bottomvalve, and the various cycling steps that are taken. For example, FIG.29 shows the pressure within the injection pipe of the well bore(pressure over time at the top is shown by the dark black line on thebottom and pressure over time at the bottom is shown by the dashed grayline on the top). According to that chart, the pressure of the LCO₂ inthe pipe begins at zero in phase 1, which corresponds to step T1 in FIG.33, in which pump 303 is off, top vent 305 is open and bottom valve 307is closed. Phase 2 as shown in FIGS. 29 and 30 is the chill-down periodthat corresponds to steps T2 through T3 of FIGS. 34 and 35, wherein thepump is on, the top vent is open and the bottom valve is closed. Duringthis phase, the pump begins operating under low power, which allows theLCO₂ to gradually begin filling up the well bore, wherein, as shown inFIG. 29, the pressure at the bottom of the injection pipe begins toincrease as the pipe is filled with LCO₂, due to the increase in headpressure created by the LCO₂ filling the pipe. At this point, while thepressure at the bottom of the pipe reaches 2,600 psig, the top vent isstill open, so the pressure at the top of the pipe (shown by the graydashed line) remains zero. Also, because the bottom valve is closed, thepressure exerted into the matrix, as shown in FIG. 30, also remainszero.

The next phase, phase 3, corresponds to T4 in FIG. 36, in which the topvent and bottom valve are closed, but now, the pump is operating at fullpower and the pressure inside the pipe begins to increase substantially,at the top and bottom of the pipe. This can be seen by the steep line onthe curves shown in FIG. 29 which indicates that the pressure at the topof the pipe increases from zero to about 2,600 psig, and the pressure atthe bottom of the pipe increases from about 2,600 to about 5,200 psig.Again, the reason there is more pressure at the bottom is due to thehead pressure created by the weight of the LCO₂ column filling up thewell bore. Because the bottom valve is closed, there is no pressurewithin the matrix, as shown in FIG. 30, during phase 3.

The next phase, phase 4, corresponds to T5 in FIG. 37, which shows thebottom valve is now open, and the top vent is now closed, but with thepump still on. The pump continues to operate at full power and continuesapplying pressure inside the pipe, but now, with the bottom valve open,the LCO₂ is released under high pressure into the matrix. Note that inFIG. 29 the curves showing the pressure inside the pipe graduallydeclines and as the LCO₂ pressure fills up the matrix spaces near theend of phase 4, there is a slight increase in back pressure, just beforethe pump is turned off. This occurs at both the top and bottom of thepipe. At the same time, the pressure of the LCO₂ exerted into the matrixfrom the pipe is preferably held constant at about 5,200 psig, by thecontinued application of pressure from the pump, as shown in FIG. 30.

Once a sufficient amount of LCO₂ is released into the matrix, during thenext phase, phase 5, which corresponds to T6, T7 and T8, in FIGS. 38 to40, the pump is turned off, and the bottom valve is closed, and the topvent is open. Note that FIG. 29 shows a dramatic drop in pressure insidethe pipe which occurs because no more pressure is applied by the pump,and the top vent is open, and soon, the pressure becomes zero. Also,since the bottom valve is closed, the pressure inside the matrix alsodramatically drops, although, as the cold LCO₂ temperatures are warmedby the surrounding formation, and changes phase to GCO₂, there is asudden and tremendous pressure increase, such as all the way up to20,000 psig, which is temporarily created by the explosive vaporizationof the liquid CO₂ to a gaseous CO₂, which helps to further break up thematrix.

In the final phase of the first cycle, phase 6, the pump stays off, thetop vent continues to be open, and the bottom valve continues to beclosed, which correlates to steps T9 to T10 in FIGS. 41 and 42. Duringthis phase, it can be seen that the pressure in the matrix continues todecline gradually, because no pressure is being added, and the CO₂continues to seep into the open cracks and fissures formed by thefracturing processes described herein. The pressure at the top of thepipe however remains zero because the top vent is open. The pressure atthe bottom of the pipe continues to fall as the LCO₂ is vented throughthe top of the pipe.

As the cycle is completed, and as more CO₂ is adsorbed and CH₄ desorbed,the pressure gradient exerted within the matrix (with more pressure nearthe injection well bores than the recovery well bores) preferably causesthe CH₄ released from the coal or shale formation to travel to therecovery well bores, wherein the CH₄ can be drawn through the pipes andcollected at the top. Also, because CO₂ is heavier, i.e., the molecularweight of CH₄ is 16 while the molecular weight of GCO₂ is 44, anyencounter between GCO₂ and GCH₄ within the matrix will advantageouslycause the CH₄ to travel upward through the cracks and fissures. Then, asthe CH₄ is extracted and recovered, it is preferably transported viapipe or truck.

The cycle is preferably repeated when the pressure inside the matrixdrops down to about 500 psig, wherein the pump is preferably turned onagain, similar to phase 2 of the first cycle, with the top vent open andthe bottom valve closed, which causes the pressure at the bottom of thepipe to increase again due to the head pressure created by the column ofLCO₂ filling the pipe. Then, phase 3 is repeated again, by turning thepump on to full power, and closing the top vent, wherein the pressure atthe top and bottom of the pipe increase again, preferably until thepressure at the bottom reaches about 5,200 psig and the pressure at thetop reaches about 2,600 psig. Then, when the pressure at the bottom ofthe pipe has reached its intended maximum amount, which in this example,is 5,200 psig, and when the pressure in the matrix has dropped down asufficient amount, such as down to about 200 psig, phase 4 is preferablyrepeated again, wherein the bottom valve is opened, and the pumpcontinues to operate at full power, thereby causing the LCO₂ to beinjected into the matrix in the form of jet streams, wherein thepressure in the matrix suddenly and dramatically rises, such as to 5,200psig. During phase 4, the pressure in the pipe gradually declines againas pressurized LCO₂ is released through the bottom valve, until it risesslightly, and then, the bottom valve is closed, and the pump is turnedoff, and the top vent is opened again. Then, during phase 5, as thepressure of LCO₂ in the matrix declines, it changes phase again, causinga sudden increase in pressure, such as up to 20,000 psig or more,causing further breakup of the matrix.

When the injection of LCO₂ into the matrix is repeated, there willalready be cavities and openings formed within the matrix from the firstcycle, such that when the high pressure LCO₂ is injected again, the jetstreams will travel further and be sustained longer as they extendfurther into the formation, until they reach the distal end of thecavity, wherein they will expand the crush zone further toward therecovery well bores. Although the pressure at the farthest distal endwill be reduced, the explosive vaporization of the LCO₂ into a gas willnevertheless cause the far end to expand further, which will help tobreak up the formation even more. This helps to avoid the need to usehorizontal pipelines extended through the formation as discussedpreviously in connection with FIG. 13. This additional injection extendsthe fracture zone ahead of the CO₂ cloud and continues to break upadditional areas toward the recovery pipes.

These figures show that there are significant pressure changes that areexperienced in the matrix, as the bottom valve is opened and closed, andas the LCO₂ released into the formation changes phase to a gaseous CO₂,wherein the increase and decrease in pressure causes additionalfractures and cleats to form, and the fractures and cleats to expand,wherein the combination of the pressure increasing and decreasing backand forth helps to rubblize and further break up the matrix, such thatmore CO₂ can be adsorbed, and more CH₄ can be desorbed and released.Thus, the method of the present invention, including the pressurecycling steps, helps to increase the productivity of the CO₂sequestration and methane recovery in coal and shale gas formations.

In latter cycles, or after the final cycle, the bottom valves can beopened and closed and configured to release high speed liquid slugs ofLCO₂ that can fly through the GCO₂ vapor, such as within thesubstantially horizontal cavities and spaces that were previously formedby the earlier cycles, to impact the distal ends of the cavities andcreate over 20,000 psig of impact pressure, which helps create a longerfracture zone that can be expanded over time. In this respect, therepeated injection of liquid CO₂ as jet streams and/or high speed slugshelps to break down the structure of the matrix, creating long narrowproliferation zones, which in the past had to be accomplished byextending long horizontal pipes through the formation.

These same steps and phases can be accomplished using the variousinjection pipe embodiments discussed herein including those with dualpipes 201, including an inner pipe 203 and outer pipe 205, wherein theLCO₂ can be injected into the inner pipe 203, while the outer valve 211is closed, and valve 209 can be operated much like the bottom valve 307of injection pipe 301.

The processes and method steps described herein are provided forexemplary purposes only and are not intended to be limiting, includingthe various pressure amounts which can be adapted to suit thecircumstances in each application. For example, when the undergroundformation is only 2,000 feet deep, the pump will have to exert morepressure, since there will be less head pressure exerted by the LCO₂column in the pipe. The relative differences in pressure between the topand bottom of the pipe will also change. Likewise, if the fracturegradient of the coal or shale found in the formation is greater or less,the pressure released into the matrix will have to be modified to ensurethat there is sufficient pressure to break up the formation.

The same processes can be repeated multiple times, or the pump and tankscan be connected to another injection pipe, so that the process can beperformed in a new location. The extraction process can take severalyears, i.e., up to 5 or more, wherein the process can be repeated untilthe maximum amount of methane is recovered and appropriate amount of CO₂is stored.

The cycling method described above helps to increase permeability of thematrix and therefore helps to quicken the delivery and arrival time ofthe CH₄ at the recovery well bores, so that the process can be completedfor any given area more efficiently. Alternatively, this enables theinjection well bores to be spaced further apart so that while thearrival time may not be enhanced, the cost of having to installadditional well bores can be reduced. This method can be used to extractmethane from a coal bed, which can then be left in place, or, in othercircumstances, the method can be used to remove dangerous CH₄ from thecoal bed, such that it can then be mined more effectively and safely,with a reduced risk of explosions occurring.

FIG. 32 shows the level of natural gas output enhanced by using theabove described processed, including 1) introducing the injected LCO₂ atpressures higher than the fracture strength of the matrix, 2)introducing pressure cycles for injecting LCO₂ between 5,000 psig and200 psig to enhance the permeability of the matrix at least one to threeorders of magnitude, and 3) maintaining the CO₂ in the matrix atrelatively low temperatures to speed up the CO₂ adsorption thatdisplaces CH₄. In particular, FIG. 32 shows the increase in volume ofnatural gas produced as volume per day that can be expected by usingvarious methods, wherein the top line represents the enhanced effectsproduced by using the present methods and processes described above(including pressure cycling through repeatedly injection of LCO₂ underpressure at greater than the fracture strength of the matrix, and usinglower temperatures for the LCO₂), the middle line represents usingliquid CO₂ as an injection with pressure under the fracture strength ofthe coal matrix, and the bottom line represents conventional methods ofcoal bed methane recovery. It can be seen that the saturation point ofmaximum recovery is achieved more quickly using the methods andprocesses described herein.

In the present invention, unlike previous hydraulic fracturing methods,there is no need for a proppant to maintain the width of the fracturesand openings created within the formation. This is because the main goalis to adsorb CO₂ onto the coal or gas shale fragments, which will occurwhen the fractures are open, and once the adsorption occurs, the CO₂will be stored and sequestered within the formation, despite whathappens when the pressure is released and the fractures are closed.Subsequent pressurization and depressurization cycles further enhancethe migration of the CH₄ previously released to work its way toward thereceiver borehole. That is, once the CO₂ has been adsorbed, and the CH₄has been desorbed and released, half the goal of the present inventionhas been completed, i.e., the CO₂ has been sequestered, and thus, atthat point, even if not all of the CH₄ has been released, so long as asufficient amount of CH₄ has been released and recovered to offset thecost of the CO₂ capture method, then, the present invention is useful.That is, during the time the fractures are open, natural gas will bereleased from the fragments and flow from the rock formation to the wellbore, such that a sufficient amount of natural gas will be recovered tooffset the cost of capturing the CO₂ gas. Since the goal of sequesteringCO₂ is as important as collecting natural gas, the method is useful evenif some of the natural gas released from the coal and/or shale remainstrapped within the formation.

Indeed, the pressurized LCO₂ within the cracks can act as proppants whenthey are yet to be adsorbed onto the surfaces they are propping. In thiscase, no proppant is needed to keep the existing fractures and newlyformed fractures from closing to recover the natural gas, but rather,because the GCO₂ adsorption is increased by high pressure and lowtemperature, GCO₂ can be adsorbed in greater quantities onto thesurfaces of the rubblized layer of coal or shale, which occurs beforethe pressure is released and the openings are closed.

The newly created surfaces within the drill hole and radiating crackscan cause the LCO₂ to warm up, although at great depth where there ishigher pressure the LCO₂ will likely remain a liquid despite thewarming. Nevertheless, as the cracks form, and pressure is reduced, atsome point, the LCO₂ will turn into GCO₂, which breaks up the matrixeven more. When the cryogenic pump is shut down, and the pressuredecreases, and when it decreases a sufficient amount, along with asufficient temperature increase, the liquid LCO₂ can suddenly changephase explosively and the gaseous GCO₂ can reach into the cracks andcreate more exposed surfaces within the stratum, thereby creatingadditional sites for CO₂ sequestration and more natural gas desorptionand release. When the high pressure LCO₂ eventually warms up andexplosively expands there will be cracks formed that extend radially asfar as, in some cases, 2,500 feet or more. This process of rubblizationexposes the material in the product zone by forming a multitude ofsmaller particles and a huge sum of exposed surfaces that are madeavailable for the capture of GCO₂ and release of CH₄.

While it is preferable that this phase change occurs after the pump isturned off, and the valves in the pipes are closed, because the LCO₂ iswarmed by the temperature of the surrounding rock, there is apossibility that the phase change could occur before the valves areclosed. Indeed, because of the lower pressures that exist at shallowerdepths, this may be more likely to occur in a shallower formation. Thus,at shallower depths, natural ambient warming in the coal or shale layermay cause an explosive change of phase to occur from liquid LCO₂ to gasGCO₂ early on, wherein the LCO₂ or GCO₂ adsorption can further displacethe methane CH₄. Thus it is vital to install a check valve in thepipeline just above the valve to protect the pipeline and the pump.

In any event, this sudden phase change radiates fractures in alldirections to further rubblize the stratum. The proposed approach willattain the explosive rubblization effect by introducing high pressureliquid CO₂ into the pipe and releasing it through the holes to create ahigh pressure liquid CO₂ jet. It will be necessary for the cryogenicpump to sustain the pressure of the LCO₂ in ever increasing volumes offractures when the ambient shale or coal is at greater depth (highambient stress) where the fractures occur to prevent prematurevaporization. On the other hand, when the local warm shale or coal atshallow depth (low ambient stress) causes the liquid CO₂ to flash intogaseous CO₂, an even higher pressure can be achieved and furtherfragmentation occurs. At a depth of 1,000 feet, for example, in a coalbed or shale layer that has a 0.823 psi/ft. fracture gradient, only 823psi LCO₂ forced through a one inch diameter hole in the pipe is neededto fracture and create a substantially horizontal 1,250 feet long,pencil-like cavity. Then, when the pressure drops to 400 psi, and thetemperature warms to plus 40° F., for example (or elsewhere along thephase change line 85 in FIG. 7), the LCO₂ will flash off and explosivelyincrease its specific volume to form GCO₂. This explosive effect causesmore micro-fractures to occur, which facilitates the simultaneousdesorption of CH₄ and the adsorption of LCO₂ or GCO₂.

In another example, at a depth of 5,000 feet, in a coal bed or shalelayer that has a 0.9 psi/ft. fracture gradient, 4,500 psi is needed tofracture and create a 1,250 feet long, horizontal pencil-like cavity. Insuch case, there will be no flashover to a gas even if the layer iswarmer than plus 60° F. because of the greater pressures involved—theCO₂ will remain a liquid although it will require the action of thesurface level pump to continuously supply the rated 4,500 psi to causemore and more fracturing and penetration of the LCO₂ into the naturalcracks. Then, when all the required LCO₂ is supplied to meet thecapacity of the layer to adsorb the CO₂, the pumping is stopped. Then,when the pressure in the layer drops a sufficient amount (such as byvirtue of more cracks being created), the LCO₂ will explosively flash toGCO₂ and cause more micro-cracks to occur. This GCO₂ will continue to beadsorbed onto the large surface area of the rubblized layer material.

The hugely increased fragmentation exposes more surface area of theshale or coal to the gaseous CO₂, and because there is more affinity forthe surface to adsorb the CO₂ than to continue holding onto the naturalgas adsorbed previously, the natural gas is desorbed and released. Then,because the released methane is light weight compared to the carbondioxide that was introduced into the formation, the methane tends tomigrate horizontally over the methane in the horizontal matrix and buoyvertically above the methane when it flows upwards through the pipes, asshown in FIG. 20.

With all vents of the LCO₂ injection pipe and the natural gas recoverypipes closed, the pressurization of the shale or coal bed is allowed tobe maintained or continued, and thus, the fracturing can continue, andCH₄ continues to be desorbed from the surface of each fracture in thepresence of the high pressure gaseous CO₂, and CO₂ continues to beadsorbed into the available surfaces just made free by desorption of theCH₄. This containment is preferably sustained for as long as needed topermit the LCO₂ to be completely vaporized to GCO₂ and the GCO₂ to becompletely adsorbed and the released lower density natural gas tomigrate into the perforated vertical collection pipes and flow upward tobe recovered. At these low temperatures the CH₄ is less dense than theLCO₂, so the CH₄ naturally rises.

The residence time for all the LCO₂ to convert to GCO₂ is preferablyfollowed to ensure maximum conversion. The GCO₂ is adsorbed onto thesurfaces of the rubblized production zone material and the natural gasis released. The present method contemplates waiting for the completionof the residence time wherein the exchange of LCO₂ to GCO₂ and then theGCO₂ exchange with natural gas (LCH₄) at each coal grain or shale grainsite continues to occur. High pressure is preferably sustained duringthis process to reduce the required residence time.

After the waiting period, which can be about two weeks, the pipe valvesare preferably opened, wherein the natural gas collection can proceed,although the rate of collection should be sufficiently slow to retainthe necessary high pressure within the stratum. That is, if the] CH₄withdrawal pipe vents are opened too early, or too quickly, pressurizedmethane will begin rising to the top, but at the expense of a largeamount of liquid CO₂ remaining within the formation that has yet to beadsorbed. By slowly opening the valves, and slowly reducing the pressurewithin the formation, this allows the low density CH₄ to buoy past theLCO₂ and allow the CH₄ to migrate to the recovery pipes, while at thesame, allowing the CO₂ stream to continue to drop below the CH₄ streamand be adsorbed, and CH₄ to continue to be desorbed. Once the cycle iscomplete, which can be ten to fourteen days, and most if not all of thenatural gas has risen, the process can be complete. Then, the recoveredCH₄ from the site can be transported via pipe or truck after it has beenpressurized. And the same process can be repeated at another site, orwithin a predetermined amount of time, the same process can be repeatedat the same site, to further increase the permeability and withdrawgreater amounts of natural gas.

There will be a period when some of the LCO₂ or GCO₂ will mix with thenatural gas, but during this period, the relative densities of the GCH₄and GCO₂ will cause the GCH₄ 150 to rise and the GCO₂ 152 to returndownward into the rubblized coal or shale, as shown in FIG. 20, forfurther adsorption and capture. FIG. 21 shows the relative densities ofCO₂ and CH₄ within the various pressures at 40 degrees F.

FIGS. 22 and 23 show two field patterns for well bores located at thesame geographical site. FIG. 22 is a representation of the site with 36wells in one direction and 36 wells in another direction, for a total of1,236 wells, wherein there is a span of 1,079 feet between each wellbore. This results in the field being 40,900 feet square in size. FIG.23 is a representation of the same site with 22 wells in one direction,and 22 wells in another direction, for a total of 484 wells, whereinthere is a span of 1,677 feet between each well bore. This results inthe field being 40,900 feet square as well. Either pattern, or anyvariation of patterns, including square, rectangular or otherconfiguration, can be used depending on the needs of the site.

What is claimed is:
 1. A method of sequestering carbon dioxide andrecovering natural gas from a coal or gas shale reservoir, comprising:capturing or producing carbon dioxide gas from coal or from flue gasesof a power plant, incinerator or chemical processing plant; cooling thecarbon dioxide gas to create liquid carbon dioxide; injecting the liquidcarbon dioxide into an injection pipe extended into said reservoir,wherein said injection pipe has perforations that allow the carbondioxide to be released into said reservoir, using the followingsteps: 1) introducing liquid nitrogen into said injection pipe topre-chill said pipe; 2) introducing said liquid carbon dioxide into saidinjection pipe gradually with a top vent of said injection pipe open anda bottom valve of said injection pipe closed; 3) turning on a pump topressurize said liquid carbon dioxide; 4) closing said top vent of saidinjection pipe and injecting said pressurized liquid carbon dioxide intosaid injection pipe until the pressure within said injection pipereaches a predetermined amount which is above the fracture strength ofsaid coal or shale in said reservoir; 5) opening said bottom valve ofsaid injection pipe and allowing said liquid carbon dioxide to bereleased under pressure through said perforations and into said coal orshale reservoir and causing the coal or shale in said reservoir to breakup; 6) closing said bottom valve and allowing said liquid carbon dioxidein said reservoir to change phase into a gaseous carbon dioxide; 7)allowing the gaseous carbon dioxide to adsorb onto the coal or shale andallowing natural gas to be desorbed and released from the coal or shale;8) recovering the natural gas released from the coal or shale throughone or more recovery pipes; and 9) repeating steps 2) through 8).
 2. Themethod of claim 1, wherein the liquid nitrogen is allowed to changephase to a gas until a steady state temperature is reached.
 3. Themethod of claim 1, wherein the step of introducing said liquid carbondioxide into said injection pipe gradually comprises allowing gasesformed as the liquid carbon dioxide changes phase to a gas to vent fromthe top of said injection pipe and doing so until a steady statetemperature of the carbon dioxide is achieved in said injection pipe,which is when the gases stop coming to the surface.
 4. The method ofclaim 1, wherein the predetermined pressure within said injection pipemeasured at the bottom exceeds the fracture strength of the coal orshale reservoir, taking into account the depth of the reservoir, and thefriction that exists along the length of said injection pipe, such thatthe liquid carbon dioxide is released with sufficient speed and pressureto form jet streams of liquid carbon dioxide that help to producefractures and openings within said reservoir.
 5. The method of claim 1,wherein after the liquid carbon dioxide is released into said reservoir,and the bottom valve is closed, the carbon dioxide is allowed to warmup, or its pressure is allowed to drop, such that a sudden phase changefrom a liquid to a gas occurs within said reservoir, wherein thetransition of the liquid carbon dioxide to a gas causes the liquid toexpand and create additional fractures and openings within saidreservoir.
 6. The method of claim 1, wherein after the liquid carbondioxide has been released into said reservoir, and said bottom valve isclosed, the carbon dioxide is allowed to be adsorbed into the coal orshale, and methane gas is allowed to be desorbed, wherein after apredetermined amount of time, said recovery pipes are opened graduallyin small increments to create a pressure gradient between the injectionpipe and recovery pipes, which in turn, allows the natural gas to flowthrough the reservoir toward the recovery pipes, and then eventuallyrise to the surface, but at the same time, for the pressure of the gasor liquid within said reservoir to be maintained above a predeterminedminimum for a predetermined amount of time.
 7. The method of claim 1,wherein injecting the liquid carbon dioxide comprises using multiplearrays of injection and recovery pipes wherein said arrays are orientedsuch that the perforations of the injection pipes extend substantiallyhorizontally into said reservoir.
 8. The method of claim 1, wherein adewatering step is performed before the liquid nitrogen is introducedinto said injection pipe.